Bill Text: IL HB3779 | 2025-2026 | 104th General Assembly | Introduced

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Bill Title: Creates the Municipal and Cooperative Electric Utility Planning and Transparency Act. Provides that, by November 1, 2025, and by November 1 every 3 years thereafter, all electric cooperatives with members in the State, municipal power agencies, and municipalities shall file with the Illinois Power Agency an integrated resource plan. Sets forth provisions concerning the plan. Amends the Illinois Power Agency Act. Authorizes the Illinois Power Agency to develop capacity procurement plans and conduct competitive procurement processes for the procurement of capacity needed to ensure environmentally sustainable long-term resource adequacy across the State at the lowest cost over time. Amends the Public Utilities Act. Changes the cumulative persisting annual savings goals for electric utilities that serve less than 3,000,000 retail customers but more than 500,000 retail customers for the years of 2025 through 2030. Provides that the cumulative persisting annual savings goals beyond the year 2030 shall increase by 0.9 (rather than 0.6) percentage points per year. Changes the requirements for submitting proposed plans and funding levels to meet savings goals for an electric utility serving more than 500,000 retail customers (rather than serving less than 3,000,000 retail customers but more than 500,000 retail customers). Provides that an electric utility that has a tariff approved within one year of the amendatory Act shall also offer at least one market-based, time-of-use rate for eligible retail customers that choose to take power and energy supply service from the utility. Sets forth provisions regarding the Illinois Commerce Commission's powers and duties related to residential time-of-use pricing. Provides that each capacity procurement event may include the procurement of capacity through a mix of contracts with different terms and different initial delivery dates. Sets forth the requirements of prepared capacity procurement plans. Requires each alternative electric supplier to make payment to an applicable electric utility for capacity, receive transfers of capacity credits, report capacity credits procured on its behalf to the applicable regional transmission organization, and submit the capacity credits to the applicable regional transmission organization under that regional transmission organization's rules and procedures. Makes other changes.

Spectrum: Partisan Bill (Democrat 1-0)

Status: (Introduced) 2025-02-07 - Filed with the Clerk by Rep. Ann M. Williams [HB3779 Detail]

Download: Illinois-2025-HB3779-Introduced.html

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104TH GENERAL ASSEMBLY State of Illinois 2025 and 2026 HB3779 Introduced , by Rep. Ann M. Williams SYNOPSIS AS INTRODUCED:
See Index
Creates the Municipal and Cooperative Electric Utility Planning and Transparency Act. Provides that, by November 1, 2025, and by November 1 every 3 years thereafter, all electric cooperatives with members in the State, municipal power agencies, and municipalities shall file with the Illinois Power Agency an integrated resource plan. Sets forth provisions concerning the plan. Amends the Illinois Power Agency Act. Authorizes the Illinois Power Agency to develop capacity procurement plans and conduct competitive procurement processes for the procurement of capacity needed to ensure environmentally sustainable long-term resource adequacy across the State at the lowest cost over time. Amends the Public Utilities Act. Changes the cumulative persisting annual savings goals for electric utilities that serve less than 3,000,000 retail customers but more than 500,000 retail customers for the years of 2025 through 2030. Provides that the cumulative persisting annual savings goals beyond the year 2030 shall increase by 0.9 (rather than 0.6) percentage points per year. Changes the requirements for submitting proposed plans and funding levels to meet savings goals for an electric utility serving more than 500,000 retail customers (rather than serving less than 3,000,000 retail customers but more than 500,000 retail customers). Provides that an electric utility that has a tariff approved within one year of the amendatory Act shall also offer at least one market-based, time-of-use rate for eligible retail customers that choose to take power and energy supply service from the utility. Sets forth provisions regarding the Illinois Commerce Commission's powers and duties related to residential time-of-use pricing. Provides that each capacity procurement event may include the procurement of capacity through a mix of contracts with different terms and different initial delivery dates. Sets forth the requirements of prepared capacity procurement plans. Requires each alternative electric supplier to make payment to an applicable electric utility for capacity, receive transfers of capacity credits, report capacity credits procured on its behalf to the applicable regional transmission organization, and submit the capacity credits to the applicable regional transmission organization under that regional transmission organization's rules and procedures. Makes other changes.
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A BILL FOR
HB3779 LRB104 11172 AAS 21254 b
AN ACT concerning regulation.
Be it enacted by the People of the State of Illinois,
represented in the General Assembly:
Section 1. Short title. This Act may be cited as the
Municipal and Cooperative Electric Utility Planning and
Transparency Act.
Section 5. Legislative findings and objectives. The
General Assembly finds:
(1) Municipal and cooperative electric utilities
provide electricity to more than 1,000,000 State
residents.
(2) These utilities are managed by elected officials,
elected board members, or their appointees. Due to their
governance structures, municipal and cooperative electric
utilities are exempt from certain regulatory requirements
and oversight under State and federal law.
(3) State residents who are served by these utilities,
and who pay rates for electricity set by these utilities,
often lack access to important information about these
utilities' generation portfolios, procurement, management
practices, and budgets. Because democratic elections by
member-ratepayers or customers are the ultimate guarantor
of the integrity and cost-effectiveness of these

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utilities' operations, access to this information is
crucial to ensuring management of these utilities is
prudent and responsive.
(4) Good utility practice entails long-term planning
on the part of a utility, including anticipating
retirement of existing generation resources, planning new
generation build or purchase well in advance of any
capacity shortfall, and developing rigorous estimates of
future load to inform procurement, construction, and
retirement decisions.
(5) In many other states, integrated resource planning
processes have been used to avoid capacity shortfalls,
minimize ratepayer costs, and increase public
participation in and knowledge of electric generation
portfolio choices, even where the planning utility is not
otherwise subject to rate approval by the state.
(6) It is in the best interests of State electricity
customers and member-ratepayers that electricity is
provided by a portfolio of generation and storage
resources and demand-side programs that minimizes both
cost and environmental impacts and that long-term utility
planning can and should facilitate the achievement of such
portfolios.
(7) With the enactment of the Inflation Reduction Act
of 2022, municipal and cooperative electric utilities have
access to a variety of federal funding streams designed to

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facilitate transition from fossil fuel to renewable
generation. Consistent with Congressional intent,
municipal and cooperative electric utilities should
perform a comprehensive analysis of their existing
portfolio and have a duty, as utility managers, to
identify opportunities to minimize member-ratepayer and
customer costs.
(8) To ensure utilities minimize ratepayer costs,
maximize opportunities for transition from fossil fuels to
renewable resources, and to increase transparency and
democratic participation, it is important that municipal
and cooperative electric utilities participate in an
integrated resource planning process with public
participation and Illinois Power Agency oversight.
Section 10. Definitions. As used in this Act:
"Agency" means the Illinois Power Agency.
"Demand-side program" means a program implemented by or on
behalf of a utility to reduce retail customer consumption
(MWh) or shift the time of consumption of energy (MW) from end
users, including energy efficiency programs, demand-response
programs, and programs for the promotion or aggregation of
distributed generation.
"Electric cooperative" has the meaning given to that term
in Section 3-119 of the Public Utilities Act.
"Generation resource" means a facility for the generation

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of electricity.
"Municipal power agency" has the meaning given to that
term in Section 11-119.1-3 of the Illinois Municipal Code.
"Municipality" has the meaning given to that term in
Section 11-119.1-3 of the Illinois Municipal Code.
"Renewable generation resource" means a resource for
generating electricity that uses wind, solar, or geothermal
energy.
"Storage resource" means a commercially available
technology that uses mechanical, chemical, or thermal
processes to store energy and deliver the stored energy as
electricity for use at a later time and is capable of being
controlled by the distribution or transmission entity managing
it, to enable and optimize the safe and reliable operation of
the electric system.
"Utility" means a municipal power agency, municipality, or
electric cooperative.
Section 15. Purpose and contents of integrated resource
plan.
(a) By November 1, 2025, and by November 1 every 3 years
thereafter, all electric cooperatives with members in this
State, municipal power agencies, and municipalities shall file
with the Agency an integrated resource plan, except that
municipalities and electric cooperatives that are members of,
and have a full requirements contract with, a municipal power

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agency or electric cooperative subject to this Act may file a
statement adopting such other utility's integrated resource
plan.
(b) The purposes of the integrated resource plan are to
provide a comprehensive description of the utility's current
portfolio of electrical generation, storage, demand-side
programs, and transmission resources, to forecast future load
changes to facilitate prudent planning with respect to
resource procurement and retirement, to determine what
resource portfolio will meet ratepayers' needs while
minimizing cost and environmental impact, and to articulate
steps the utility will take to reduce customer costs and
environmental impacts through changes to its current
generation portfolio through construction, procurement,
retirement, or demand-side programs.
(c) As part of the integrated resource plan development
process, a utility shall consider all resources reasonably
available or reasonably likely to be available during the
relevant time period to satisfy the demand for electricity
services for a 20-year planning period, taking into account
both supply-side and demand-side electric power resources.
(d) An integrated resource plan shall include, at a
minimum:
(1) A list of all electricity generation facilities
owned by the utility, in whole or in part. For each such
facility, the integrated resource plan shall report:

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(A) general location;
(B) ownership information, if ownership is shared
with another entity;
(C) type of fuel;
(D) the date of commercial operation;
(E) expected useful life;
(F) expected retirement date for any resource
expected to retire within the next 10 years, and an
explanation of the reason for the retirement;
(G) nameplate and peak available capacity;
(H) total MWh generated at the facility during the
previous calendar year;
(I) the date on which the facility is anticipated
to be fully depreciated; and
(J) any compliance obligations, or compliance
obligations expected to apply within the next 10
years, and any proposed or anticipated expenditures
intended to meet those obligations.
(2) A list of all power purchase agreements to which
the utility is a party, whether as purchaser or seller,
including the counterparty, general location and type of
generation resource providing power per the agreement,
date on which the agreement was entered into, duration of
the agreement, and the energy and capacity terms of the
agreement.
(3) A list of any sale transactions of any energy or

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capacity to any purchaser.
(4) A list of any demand-side programs and total
distributed generation.
(5) A narrative description of all existing
transmission facilities owned by the utility, in whole or
in part, that identifies any transmission constraints or
critical contingencies, and identification of the regional
transmission organization, if any, which exercises
operational control over the transmission facility.
(6) A list of all capital expenditures exceeding
$1,000,000 in the previous calendar year that includes a
brief description of the expenditure, the total amount
expended, and whether the expenditure was required to
conform with State or federal law, rule, or regulation;
(7) A description of all transmission costs,
disaggregated by expenditure, that identifies all capital
expenditures on physical infrastructure and contracts for
rights costing greater than $1,000,000 over the term of
the agreement.
(8) A copy of the most recent FERC Form 1 filed by the
utility. If no such FERC Form 1 has been filed, the utility
shall complete a FERC Form 1 for the prior calendar year.
(9) A range of load forecasts for the 5-year planning
period that includes hourly data representing a high-load,
low-load, and expected-load scenario for all retail
customers, consistent with the requirements of paragraph

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(1) of subsection (d) of Section 16-111.5 of the Public
Utilities Act and any associated rules or regulations.
Such forecasts shall include:
(A) all underlying assumptions;
(B) an hourly load analysis consistent with the
requirements of paragraph (1) of subsection (b) of
Section 16-111.5 of the Public Utilities Act;
(C) analysis of the impact of any demand-side
programs, consistent with paragraph (2) of subsection
(b) of Section 16-111.5 of the Public Utilities Act;
(D) any reserve margin or other obligations placed
on the utility by regional transmission organizations
to which it is a member; and
(E) to the extent the information is available, an
assessment of the accuracy of any past load forecasts
submitted pursuant to this Section and an explanation
of any deviation of greater than 10% in either
direction from the forecasted load.
(10) The results of an all-source request for
proposals for generation resources and capacity contracts.
(11) A 5-year action plan for meeting the forecasted
load that minimizes customer cost and adverse
environmental impacts. As part of the action plan, the
utility shall:
(A) Identify any generation or storage resources
anticipated to be removed from service in the 5 years

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following the date on which the integrated resource
plan is submitted.
(B) Determine whether given forecasted load growth
or unit retirements, or both, the utility will need to
procure additional capacity and energy, and provide a
quantitative estimate of any such gap between
forecasted load and supply-side resources.
(C) Provide a narrative description of the
utility's process for evaluating possible resources to
secure this additional capacity and energy.
(D) Provide a narrative description of the
utility's processes for assessing the present economic
value of existing generation and state whether,
consistent with this methodology, any currently
operating units, if any, could be replaced by other
resources at lower cost to ratepayers.
(E) Identify a preferred portfolio of generation,
storage, and demand-side programs that, in the
utility's judgment, meets its forecasted load while
minimizing the ratepayer cost and environmental
impacts to the extent reasonably achievable in the 5
years covered by the action plan. The portfolio shall
incorporate any capacity or other reliability
requirements of any regional transmission organization
of which the utility is a member.
(F) Identify, if the preferred portfolio includes

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the construction of new generation or storage
resources or transmission facilities, the preferred
site for all new construction of generation, storage,
or transmission facilities.
(G) If the utility states that it intends to
remove a generation resource from service, include in
the integrated resource plan a statement describing
the utility's plan to minimize economic impacts to
workers due to facility retirement. This statement
shall include a description of:
(i) the utility's efforts to collaborate with
the workers and their designated representatives,
if any;
(ii) a transition timeline or date certain on
which such a transition timeline shall be made
available to ensure certainty for workers;
(iii) the utility's efforts to protect pension
benefits and extend or replace health insurance,
life insurance, and other employment benefits;
(iv) all training and skill development
programs to be made available for workers who will
see their employment reduced or eliminated as a
result of the retirement; and
(v) any agreements with local governments
regarding continuing tax or other transfer
payments following the facility's retirement

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intended to minimize the impact on local services.
(H) Describe any anticipated capital expenditures
in excess of $1,000,000 at existing generation
facilities and the reason for such expenditures.
(12) A description of all models and methodologies
used in performing the integrated resource planning
process. The utility shall provide to the Agency, upon
request, reasonable access to any computer models used in
the analysis and workpapers, in electronic form, relied on
in preparation of the report.
(e) As part of all integrated resource plans submitted in
2025, the utility shall identify all programs, grants, loans,
or tax benefits for which the utility is eligible pursuant to
the Inflation Reduction Act of 2022, and state whether the
utility has applied for or otherwise used the program, grant,
loan, or tax benefit. If the utility has not yet applied for or
utilized the benefit, the utility shall state whether it
intends to do so.
(f) Each utility shall submit, as part of its integrated
resource plan, a least cost plan for constructing or procuring
renewable energy resources to meet a minimum percentage of its
load for all retail customers as follows: 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.
(g) Beginning in 2031, each utility shall submit, as part

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of its integrated resource plan, a least cost plan for
supplying 100% of its total projected load through renewable
generation resources in combination with storage resources and
demand-side programs by 2045. This least cost plan shall
provide for the retirement of all coal and gas generation
resources by January 1, 2045.
(h) The Agency may adopt rules establishing additional
requirements as to the form and content of integrated resource
plans, including, but not limited to, specifying forecast
methodologies.
Section 20. Stakeholder process. Prior to the submission
of an integrated resource plan, a municipality, municipal
power agency, or electric cooperative required to submit an
integrated resource plan shall hold at least 2 stakeholders
meetings open to all ratepayers and members of the public.
Notice of the meetings shall be sent to all customers not less
than 30 days prior to the meeting. During the meetings the
utility shall describe its processes for developing the
integrated resource plan and its core assumptions and
constraints, present its proposed preferred portfolio, and
describe any planned retirements, capital expenditures on
existing generation resources likely to exceed $1,000,000, and
planned construction. Each meeting shall allow time for public
comment and the utility shall provide attendees with a means
of providing public comment in writing following the meeting.

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Section 25. Procedures for submission of integrated
resource plan.
(a) Each municipality, municipal power agency, and
electric cooperative shall submit its integrated resource
plan, as set forth in this Act, to the Agency by October 1 of
the calendar year.
(b) The Agency may request further information from the
utility. Any such requests shall be made in writing. If the
Agency requests additional information, the utility shall
provide responses no later than 15 days following the request.
(c) The Agency shall facilitate public comment on the
integrated resource plan, as follows:
(1) upon submission of the integrated resource plan,
the Agency shall post the integrated resource plan
publicly on its website. The plan shall remain publicly
accessible for at least 60 days.
(2) the utility shall hold at least 2 public meetings,
one in person and one remotely, where it shall make a
representative available to address questions about the
resource plan. The meetings shall be held no sooner than
15 days, and no later than 45 days, after the integrated
resource plan is made available to the public.
(3) the Agency shall accept public comments on the
integrated resource plan for 60 days following its public
posting via website, email, or mail. The Agency may extend

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this public comment period by an additional 60 days upon
request by members of the public; and
(4) after the conclusion of the public comment period,
as determined by the Agency, the Agency shall transmit
copies of all public comments received to the utility.
(d) The utility shall review public comments and provide
responses that reasonably address all issues or questions
raised by such comments. The utility may modify its integrated
resource plan in response to these comments. The utility shall
prepare a document with responses to public comments and
submit this response document to the Agency no later than 90
days after receiving the comments from the agency. This
response document shall be posted publicly on the Agency's
website along with the original integrated resource plan, as
submitted, and any revisions made by the utility in response
to public comments.
(e) The Agency shall maintain public access to all
integrated resource plans submitted pursuant to this Act,
accessible through the Agency's website, for no less than 10
years following each integrated resource plan's initial
submission.
Section 30. Cost of Service Study.
(a) All electric cooperatives with members in this State,
municipal power agencies, and municipalities with $5,000,000
or more in total retail electricity revenues shall submit to

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the Agency an embedded cost-of-service study on November 1,
2025 and on November 1 every 3 years thereafter.
(b) The format and contents of such study shall be
consistent with those set forth in any rules or regulations by
the Illinois Commerce Commission for cost-of-service studies
by electric utilities subject to retail rate approval by the
Commerce Commission.
Section 35. Use of independent expert.
(a) The Agency shall maintain a list of qualified experts
or expert consulting firms for the purpose of developing
integrated resource plans on behalf of municipalities,
municipal power agencies, and cooperatives. In order to
qualify an expert or expert consulting firm must have:
(1) direct previous experience assembling power supply
plans or portfolios for utilities;
(2) an advanced degree in economics, mathematics,
engineering, risk management, or a related area of study;
(3) 10 years of experience in the electricity sector;
(4) expertise in wholesale electricity market rules,
including those established by the federal Energy
Regulatory Commission and regional transmission
organizations; and
(5) adequate resources to perform and fulfill the
required functions and responsibilities.
(b) The Agency may assemble the list as part of the process

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for developing a list of qualified experts for experts to
develop procurement plans, as set forth in subsection (a) of
Section 1-75 of the Illinois Power Agency Act.
(c) 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
prepare the integrated resource plan on behalf of the utility.
The Agency shall also provide each qualified expert's or
expert consulting firm's response to the request for
qualifications. A utility shall, within 5 business days,
notify the Agency in writing if it objects to any experts or
expert consulting firms on the lists. Objections shall be
based on:
(1) the failure to satisfy qualification criteria;
(2) the identification of a conflict of interest; or
(3) the 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 the list, the
objecting utility may withdraw its application and develop its
integrated resource plan without agency assistance.
(d) A utility required to submit an integrated resource

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plan may elect to rely on an expert or expert consulting firm
selected by the Agency to develop the plan and conduct
stakeholder processes.
(e) A utility may submit a request to the Agency, not less
than 6 months prior to the date on which the integrated
resource plan is due, for such an expert or expert consulting
firm.
(f) Upon receipt of such a request, the Agency shall issue
requests for proposals to the qualified experts on the list
assembled as set forth in subsections (a) through (c) to
develop an integrated resource plan for that utility. The
Agency shall select an expert or expert consulting firm to
develop the integrated resource plan on behalf of the utility
based on the proposals submitted.
(g) Subject to appropriation, if a utility elects to rely
on an expert or expert consulting firm selected by the Agency,
90% of the costs assessed by the expert for development of the
integrated resource plan shall be paid by the Agency, up to
$250,000, and the remainder paid by the utility.
Section 40. Electric cooperatives member access.
(a) As used in this Section, "meeting" has the meaning
given to that term in Section 1.02 of the Open Meetings Act.
(b) As used in this Section, except for subsection (j),
"member" includes all members of an electric cooperative in
accordance with the cooperative's bylaws. Where a generation

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and transmission electric cooperative's members are electric
cooperatives rather than individuals, members of those
member-cooperatives are members of the generation and
transmission electric cooperative for purposes of this
Section. As used in subsection (j), "member" includes only
members of an electric cooperative with individual members.
(c) All meetings of an electric cooperative shall be open
to all members, except that a cooperative, by a two-thirds
affirmative vote of the board members present, may go into
executive session for consideration of documents or
information deemed to be confidential for legal, commercial,
or personnel purposes.
(1) Before a board of directors convenes in executive
session, the board shall announce the general topic of the
executive session.
(2) Notice of all meetings of an electric cooperative
shall be posted on the website of the electric cooperative
at least 30 days prior to the meeting, except for any
annual meeting, which shall be posted at least 120 days
prior. Minutes of all meetings of an electric cooperative
shall be posted on the website of the electric cooperative
as soon as they have been approved and shall remain posted
for at least one year after the date of the meeting. Upon
request of a member, the electric cooperative shall make
minutes of any meeting held after the effective date of
this Act available. Minutes shall include the votes of

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each member of the board on all items for which approval
was not unanimous.
(3) At every regular meeting of the governing body of
an electric cooperative, members of the cooperative shall
be given an opportunity to address the board on any matter
concerning the policies and businesses of the cooperative.
The board may place reasonable, viewpoint-neutral
restrictions on the amount and duration of member comment.
(d) Each electric cooperative shall post on its website
its current rates. The electric cooperative shall keep and
make available to any member, upon request, all financial
audits of the electric cooperative conducted in the last 3
fiscal years.
(e) Each electric cooperative shall adopt and post a
written policy governing the election of directors on its
website. The electric cooperative shall provide notice of the
policy at the time a person becomes a member, as a bill insert
at least once per year, and on request. The policy shall
contain true and complete information on the following:
(1) Who is entitled to vote in an election, including
how member cooperatives may vote.
(2) How a member may obtain and cast a ballot.
(3) The postmark deadline for any ballots submitted by
mail.
(4) How a member may become a candidate for the board
or any other elected leadership positions.

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(f) Electric cooperatives shall enable their members to
vote in any election for one or more directors by mail-in
ballot, as follows:
(1) The electric cooperative shall affirmatively mail
each of its members a ballot no later than 30 days before
ballots are due. Ballots may be mailed separately and
clearly marked as such or included as a bill insert.
(2) The electric cooperative shall accept ballots by
mail if postmarked by the date indicated in the
cooperative's written policy.
(3) The electric cooperative may allow for in-person
voting in addition to mail.
(g) Electric cooperatives may establish a system for
online voting in addition to a mail-in option.
(h) At least 120 days before each board election, the
electric cooperative shall post a list of candidates and
deadline to return ballots on its website and leave the
information posted until the election has concluded. The same
information shall be included as part of a bill insert for a
billing cycle occurring at no more than 120 but no fewer than
15 days prior to the deadline to return ballots.
(i) Each candidate for a position on the board of
directors who has qualified under the electric cooperative's
bylaws is entitled to receive a membership list in electronic
format upon receipt and verification of any candidacy
requirements. Such a list shall be provided to a candidate no

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later than 15 days after requested by the candidate. The
membership list must include the names, phone numbers, and
addresses of all members as they appear in the electric
cooperative's records.
Section 45. Conflict of interest.
(a) Each electric cooperative, municipality, and municipal
power agency shall adopt, and post publicly on its website,
written policies concerning:
(1) The compensation provided to a director on the
board of directors, including information on any
authorized per diem amounts, and the values of other
benefits, services, or goods that a director receives.
(2) The disclosure of any gifts received by a director
in excess of a de minimis amount.
(3) The requirements and procedures for a director on
the board of directors to disclose in writing any
conflicts of interest. At a minimum, the policy must
require disclosure when a decision before the board could
provide directly and as a proximate result of the decision
a financial or other material benefit to:
(A) The director, if the benefit is unique to that
director and not shared by similarly situated
cooperative members.
(B) A parent, grandparent, spouse, partner in a
civil union, child, or sibling of the director, if the

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benefit is unique to that director and not shared by
similarly situated cooperative members.
(C) An entity in which the director is an officer
or director or has a financial interest not shared by
similarly situated cooperative members.
(b) Each electric cooperative shall disclose on its
website all lobbying activities as defined by Section 2 of the
Lobbyist Registration Act and the amount of expenditures on
such activities on an annual basis. Where the electric
cooperative is a member of a trade association or other
organization that engages in lobbying activities, the electric
cooperative shall post the amount of dues or other
expenditures paid by the cooperative to such an organization
and what percentage of the organization or association's
budget is spent on lobbying activities.
(c) Notwithstanding any other law to the contrary, if an
individual is a director on the board of directors of both a
distribution cooperative electric association and a generation
and transmission cooperative association, the director owes
fiduciary duties to both associations and shall not be
required to give priority to a fiduciary duty the director
owes to one association over the duties the director owes to
the other association.
Section 90. The Open Meetings Act is amended by changing
Section 2 as follows:

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(5 ILCS 120/2) (from Ch. 102, par. 42)
Sec. 2. Open meetings.
(a) Openness required. All meetings of public bodies shall
be open to the public unless excepted in subsection (c) and
closed in accordance with Section 2a.
(b) Construction of exceptions. The exceptions contained
in subsection (c) are in derogation of the requirement that
public bodies meet in the open, and therefore, the exceptions
are to be strictly construed, extending only to subjects
clearly within their scope. The exceptions authorize but do
not require the holding of a closed meeting to discuss a
subject included within an enumerated exception.
(c) Exceptions. A public body may hold closed meetings to
consider the following subjects:
(1) The appointment, employment, compensation,
discipline, performance, or dismissal of specific
employees, specific individuals who serve as independent
contractors in a park, recreational, or educational
setting, or specific volunteers of the public body or
legal counsel for the public body, including hearing
testimony on a complaint lodged against an employee, a
specific individual who serves as an independent
contractor in a park, recreational, or educational
setting, or a volunteer of the public body or against
legal counsel for the public body to determine its

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validity. However, a meeting to consider an increase in
compensation to a specific employee of a public body that
is subject to the Local Government Wage Increase
Transparency Act may not be closed and shall be open to the
public and posted and held in accordance with this Act.
(2) Collective negotiating matters between the public
body and its employees or their representatives, or
deliberations concerning salary schedules for one or more
classes of employees.
(3) The selection of a person to fill a public office,
as defined in this Act, including a vacancy in a public
office, when the public body is given power to appoint
under law or ordinance, or the discipline, performance or
removal of the occupant of a public office, when the
public body is given power to remove the occupant under
law or ordinance.
(4) Evidence or testimony presented in open hearing,
or in closed hearing where specifically authorized by law,
to a quasi-adjudicative body, as defined in this Act,
provided that the body prepares and makes available for
public inspection a written decision setting forth its
determinative reasoning.
(4.5) Evidence or testimony presented to a school
board regarding denial of admission to school events or
property pursuant to Section 24-24 of the School Code,
provided that the school board prepares and makes

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available for public inspection a written decision setting
forth its determinative reasoning.
(5) The purchase or lease of real property for the use
of the public body, including meetings held for the
purpose of discussing whether a particular parcel should
be acquired.
(6) The setting of a price for sale or lease of
property owned by the public body.
(7) The sale or purchase of securities, investments,
or investment contracts. This exception shall not apply to
the investment of assets or income of funds deposited into
the Illinois Prepaid Tuition Trust Fund.
(8) Security procedures, school building safety and
security, and the use of personnel and equipment to
respond to an actual, a threatened, or a reasonably
potential danger to the safety of employees, students,
staff, the public, or public property.
(9) Student disciplinary cases.
(10) The placement of individual students in special
education programs and other matters relating to
individual students.
(11) Litigation, when an action against, affecting or
on behalf of the particular public body has been filed and
is pending before a court or administrative tribunal, or
when the public body finds that an action is probable or
imminent, in which case the basis for the finding shall be

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recorded and entered into the minutes of the closed
meeting.
(12) The establishment of reserves or settlement of
claims as provided in the Local Governmental and
Governmental Employees Tort Immunity Act, if otherwise the
disposition of a claim or potential claim might be
prejudiced, or the review or discussion of claims, loss or
risk management information, records, data, advice or
communications from or with respect to any insurer of the
public body or any intergovernmental risk management
association or self insurance pool of which the public
body is a member.
(13) Conciliation of complaints of discrimination in
the sale or rental of housing, when closed meetings are
authorized by the law or ordinance prescribing fair
housing practices and creating a commission or
administrative agency for their enforcement.
(14) Informant sources, the hiring or assignment of
undercover personnel or equipment, or ongoing, prior or
future criminal investigations, when discussed by a public
body with criminal investigatory responsibilities.
(15) Professional ethics or performance when
considered by an advisory body appointed to advise a
licensing or regulatory agency on matters germane to the
advisory body's field of competence.
(16) Self evaluation, practices and procedures or

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professional ethics, when meeting with a representative of
a statewide association of which the public body is a
member.
(17) The recruitment, credentialing, discipline or
formal peer review of physicians or other health care
professionals, or for the discussion of matters protected
under the federal Patient Safety and Quality Improvement
Act of 2005, and the regulations promulgated thereunder,
including 42 C.F.R. Part 3 (73 FR 70732), or the federal
Health Insurance Portability and Accountability Act of
1996, and the regulations promulgated thereunder,
including 45 C.F.R. Parts 160, 162, and 164, by a
hospital, or other institution providing medical care,
that is operated by the public body.
(18) Deliberations for decisions of the Prisoner
Review Board.
(19) Review or discussion of applications received
under the Experimental Organ Transplantation Procedures
Act.
(20) The classification and discussion of matters
classified as confidential or continued confidential by
the State Government Suggestion Award Board.
(21) Discussion of minutes of meetings lawfully closed
under this Act, whether for purposes of approval by the
body of the minutes or semi-annual review of the minutes
as mandated by Section 2.06.

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(22) Deliberations for decisions of the State
Emergency Medical Services Disciplinary Review Board.
(23) The operation by a municipality of a municipal
utility or the operation of a municipal power agency or
municipal natural gas agency when the discussion involves
(i) trade secrets, (ii) ongoing contract negotiations or
results of a request for proposals relating to the
purchase, sale, or delivery of electricity or natural gas
from nonaffiliate entities, or (iii) information
prohibited from disclosure by a regional transmission
organization to ensure the integrity of competitive
markets contracts relating to the purchase, sale, or
delivery of electricity or natural gas or (ii) the results
or conclusions of load forecast studies.
(24) Meetings of a residential health care facility
resident sexual assault and death review team or the
Executive Council under the Abuse Prevention Review Team
Act.
(25) Meetings of an independent team of experts under
Brian's Law.
(26) Meetings of a mortality review team appointed
under the Department of Juvenile Justice Mortality Review
Team Act.
(27) (Blank).
(28) Correspondence and records (i) that may not be
disclosed under Section 11-9 of the Illinois Public Aid

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Code or (ii) that pertain to appeals under Section 11-8 of
the Illinois Public Aid Code.
(29) Meetings between internal or external auditors
and governmental audit committees, finance committees, and
their equivalents, when the discussion involves internal
control weaknesses, identification of potential fraud risk
areas, known or suspected frauds, and fraud interviews
conducted in accordance with generally accepted auditing
standards of the United States of America.
(30) (Blank).
(31) Meetings and deliberations for decisions of the
Concealed Carry Licensing Review Board under the Firearm
Concealed Carry Act.
(32) Meetings between the Regional Transportation
Authority Board and its Service Boards when the discussion
involves review by the Regional Transportation Authority
Board of employment contracts under Section 28d of the
Metropolitan Transit Authority Act and Sections 3A.18 and
3B.26 of the Regional Transportation Authority Act.
(33) Those meetings or portions of meetings of the
advisory committee and peer review subcommittee created
under Section 320 of the Illinois Controlled Substances
Act during which specific controlled substance prescriber,
dispenser, or patient information is discussed.
(34) Meetings of the Tax Increment Financing Reform
Task Force under Section 2505-800 of the Department of

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Revenue Law of the Civil Administrative Code of Illinois.
(35) Meetings of the group established to discuss
Medicaid capitation rates under Section 5-30.8 of the
Illinois Public Aid Code.
(36) Those deliberations or portions of deliberations
for decisions of the Illinois Gaming Board in which there
is discussed any of the following: (i) personal,
commercial, financial, or other information obtained from
any source that is privileged, proprietary, confidential,
or a trade secret; or (ii) information specifically
exempted from the disclosure by federal or State law.
(37) Deliberations for decisions of the Illinois Law
Enforcement Training Standards Board, the Certification
Review Panel, and the Illinois State Police Merit Board
regarding certification and decertification.
(38) Meetings of the Ad Hoc Statewide Domestic
Violence Fatality Review Committee of the Illinois
Criminal Justice Information Authority Board that occur in
closed executive session under subsection (d) of Section
35 of the Domestic Violence Fatality Review Act.
(39) Meetings of the regional review teams under
subsection (a) of Section 75 of the Domestic Violence
Fatality Review Act.
(40) Meetings of the Firearm Owner's Identification
Card Review Board under Section 10 of the Firearm Owners
Identification Card Act.

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(d) Definitions. For purposes of this Section:
"Employee" means a person employed by a public body whose
relationship with the public body constitutes an
employer-employee relationship under the usual common law
rules, and who is not an independent contractor.
"Public office" means a position created by or under the
Constitution or laws of this State, the occupant of which is
charged with the exercise of some portion of the sovereign
power of this State. The term "public office" shall include
members of the public body, but it shall not include
organizational positions filled by members thereof, whether
established by law or by a public body itself, that exist to
assist the body in the conduct of its business.
"Quasi-adjudicative body" means an administrative body
charged by law or ordinance with the responsibility to conduct
hearings, receive evidence or testimony and make
determinations based thereon, but does not include local
electoral boards when such bodies are considering petition
challenges.
(e) Final action. No final action may be taken at a closed
meeting. Final action shall be preceded by a public recital of
the nature of the matter being considered and other
information that will inform the public of the business being
conducted.
(Source: P.A. 102-237, eff. 1-1-22; 102-520, eff. 8-20-21;
102-558, eff. 8-20-21; 102-813, eff. 5-13-22; 103-311, eff.

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7-28-23; 103-626, eff. 1-1-25.)
Section 95. The Department of Commerce and Economic
Opportunity Law of the Civil Administrative Code of Illinois
is amended by changing Section 605-1075 as follows:
(20 ILCS 605/605-1075)
Sec. 605-1075. Energy Transition Assistance Fund.
(a) The General Assembly hereby declares that management
of several economic development programs requires a
consolidated funding source to improve resource efficiency.
The General Assembly specifically recognizes that properly
serving communities and workers impacted by the energy
transition requires that the Department of Commerce and
Economic Opportunity have access to the resources required for
the execution of the programs for workforce and contractor
development, just transition investments and community
support, and the implementation and administration of energy
and justice efforts by the State.
(b) The Department shall be responsible for the
administration of the Energy Transition Assistance Fund and
shall allocate funding on the basis of priorities established
in this Section. Each year, the Department shall determine the
available amount of resources in the Fund that can be
allocated to the programs identified in this Section, and
allocate the funding accordingly. The Department shall, to the

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extent practical, consider both the short-term and long-term
costs of the programs and allocate funding so that the
Department is able to cover both the short-term and long-term
costs of these programs using projected revenue.
The available funding for each year shall be allocated
from the Fund in the following order of priority:
(1) for costs related to the Clean Jobs Workforce
Network Program, up to $21,000,000 annually prior to June
1, 2023; and $24,333,333 annually from June 1, 2023 to May
30, 2025; and $26,020,736 annually thereafter;
(2) for costs related to the Clean Energy Contractor
Incubator Program, up to $21,000,000 annually prior to
June 1, 2025 and $22,687,403 thereafter;
(3) for costs related to the Clean Energy Primes
Contractor Accelerator Program, up to $9,000,000 annually;
(4) for costs related to the Barrier Reduction
Program, up to $21,000,000 annually prior to June 1, 2025
and $22,143,079 annually thereafter;
(5) for costs related to the Jobs and Environmental
Justice Grant Program, up to $34,000,000 annually;
(6) for costs related to the Returning Residents Clean
Jobs Training Program, up to $6,000,000 annually;
(7) for costs related to Energy Transition Navigators,
up to $6,000,000 annually prior to June 1, 2025 and
$6,482,115 annually thereafter;
(8) for costs related to the Illinois Climate Works

HB3779 - 34 - LRB104 11172 AAS 21254 b
Preapprenticeship Program, up to $10,000,000 annually;
(9) for costs related to Energy Transition Community
Support Grants, up to $40,000,000 annually;
(10) for costs related to the Displaced Energy Worker
Dependent Scholarship, upon request by the Illinois
Student Assistance Commission, up to $1,100,000 annually;
(11) up to $10,000,000 annually shall be transferred
to the Public Utilities Fund for use by the Illinois
Commerce Commission for costs of administering the changes
made to the Public Utilities Act by this amendatory Act of
the 102nd General Assembly;
(12) up to $4,000,000 annually shall be transferred to
the Illinois Power Agency Operations Fund for use by the
Illinois Power Agency; and
(13) for costs related to the Clean Energy Jobs and
Justice Fund, up to $1,000,000 annually.
The Department is authorized to utilize up to 10% of the
Energy Transition Assistance Fund for administrative and
operational expenses to implement the requirements of this
Act.
(c) Within 30 days after the effective date of this
amendatory Act of the 102nd General Assembly, each electric
utility serving more than 500,000 customers in the State shall
report to the Department its total kilowatt-hours of energy
delivered during the 12 months ending on the immediately
preceding May 31. By October 31, 2021 and each October 31

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

HB3779 - 36 - LRB104 11172 AAS 21254 b
(e) The Department shall by November 30, 2021, and each
November 30 thereafter:
(1) determine the amount necessary, but not more than
$185,000,000 $180,000,000, to meet the funding needs of
the programs reliant upon the Energy Transition Assistance
Fund as a revenue source for the immediately following
calendar year;
(2) determine, based on the kilowatt-hour deliveries
for the 12 months ending on the immediately preceding May
31 reported to it by the electric utilities under
subsection (c), the total energy transition assistance
charge to be allocated to each electric utility for the
immediately following calendar year; and
(3) report the energy transition assistance charge
applicable for the immediately following calendar year to
each electric utility serving more than 500,000 customers
in the State and the Illinois Commerce Commission for
purposes of filing the tariff pursuant to Section
16-108.30 of the Public Utilities Act.
(f) The energy transition assistance charge may not exceed
$185,000,000 $180,000,000 annually. If, at the end of the
calendar year, any surplus remains in the Energy Transition
Assistance Fund, the Department may allocate the surplus from
the fund in the following order of priority:
(1) for costs related to the development of the
Stretch Energy Codes and other standards at the Capital

HB3779 - 37 - LRB104 11172 AAS 21254 b
Development Board, up to $500,000 annually, at the request
of the Board;
(2) up to $7,000,000 annually shall be transferred to
the Energy Efficiency Trust Fund and Clean Air Act Permit
Fund for use by the Environmental Protection Agency for
costs related to energy efficiency and weatherization, and
costs of implementation, administration, and enforcement
of the Clean Air Act; and
(3) for costs related to State fleet electrification
at the Department of Central Management Services, up to
$10,000,000 annually, at the request of the Department.
(Source: P.A. 102-662, eff. 9-15-21.)
Section 100. The Illinois Power Agency Act is amended by
changing Sections 1-5, 1-10, 1-20, 1-56 and 1-75 and by adding
Sections 1-79 and 1-93 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

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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
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

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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
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

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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
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.

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(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
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) To ensure the State's clean energy goals are
timely met and that reliable clean energy is produced and
available when customers need it, the Agency should begin
to procure clean power and encourage storage, including
through long-term contracts. Where the comparison shows
that clean products can be procured at or near the cost of
non-renewable products, the clean products should be
procured. This requirement will limit the State's
dependence on fossil generation and reduce the potential
need to import fossil-fueled power.

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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
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

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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
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.
(Source: P.A. 102-662, eff. 9-15-21.)
(20 ILCS 3855/1-10)
Sec. 1-10. Definitions.
"Agency" means the Illinois Power Agency.

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"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:
(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;

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(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
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

HB3779 - 46 - LRB104 11172 AAS 21254 b
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
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

HB3779 - 47 - LRB104 11172 AAS 21254 b
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
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:

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(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;
(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

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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,
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.
"Demand response" means measures that decrease peak
electricity demand or shift demand from peak to off-peak
periods.
"Department" means the Department of Commerce and Economic
Opportunity.
"Director" means the Director of the Illinois Power

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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
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).
"Electric utility" has the same definition as found in
Section 16-102 of the Public Utilities Act.
"Energy efficiency" means measures that reduce the amount
of electricity or natural gas consumed in order to achieve a

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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 resources" means commitments from the
energy storage systems to serve Illinois energy resource and
security needs as identified in the energy storage procurement
plan. "Energy storage resources" may include intangible
attributes, tolling agreements, or other mechanisms used to
incentivize successful energy storage system development.
"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
storage system" does not include technologies that require
combustion.
"Energy storage system capacity" means the nameplate
capacity of a contracted energy storage system, measured in
megawatts of alternating current.
"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

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personal services as an independent contractor.
"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 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 16-108.12 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.
"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

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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
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

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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
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

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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
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

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at the applicable Illinois trading hub, such as PJM-NIHUB or
MISO-IL, for a given settlement period.
"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
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.
"Modernized" or "retooled" means the construction, repair,
maintenance, or significant expansion of turbines and existing
hydropower dams.
"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
nameplate capacity in kilowatts AC.
"Person" means any natural person, firm, partnership,

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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
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.

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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.
"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

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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
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

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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
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

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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
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

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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, avoided societal costs
associated with reductions in greenhouse gas emissions, 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. The societal costs associated with greenhouse gas
emissions shall be assumed to be the greater of (i) $200 per
short ton, expressed in 2025 dollars, or (ii) the most
recently approved estimate developed by the federal government
using a real discount rate consistent with long-term Treasury
bond yields. Changes in greenhouse emissions from changes in
electricity consumption shall be estimated using long-run

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marginal emissions rates developed by the National Renewable
Energy Laboratory's Cambium model or other Illinois-specific
modeling of comparable analytical rigor. 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
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

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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
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

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(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
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

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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
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

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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
systems, governmental aggregators, or rural electric
cooperatives in Illinois.
(5) Conduct an initial forward procurement and develop
an energy storage procurement plan in accordance with
Section 1-93 of this Act and Section 16-111.5 of the
Public Utilities Act, and conduct competitive procurement
processes and implement programs to procure energy storage
resources as identified in the energy storage procurement
plan as developed and approved under Section 1-93 of this
Act and Section 16-111.5 of the Public Utilities Act.
(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.

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(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
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

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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
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

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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
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

HB3779 - 71 - LRB104 11172 AAS 21254 b
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
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

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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
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.
(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

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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 3855/1-56)
Sec. 1-56. Illinois Power Agency Renewable Energy
Resources Fund; Illinois Solar for All Program.
(a) The Illinois Power Agency Renewable Energy Resources
Fund is created as a special fund in the State treasury.
(b) The Illinois Power Agency Renewable Energy Resources
Fund shall be administered by the Agency as described in this
subsection (b), provided that the changes to this subsection
(b) made by Public Act 99-906 shall not interfere with
existing contracts under this Section.
(1) The Illinois Power Agency Renewable Energy
Resources Fund shall be used to purchase renewable energy
credits or fund rebates according to any approved
procurement plan developed by the Agency prior to June 1,
2017.
(2) The Illinois Power Agency Renewable Energy
Resources Fund shall also be used to create the Illinois
Solar for All Program, which provides incentives for
low-income distributed generation and community solar
projects, and other associated approved expenditures. The
objectives of the Illinois Solar for All Program are to

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bring photovoltaics to low-income communities in this
State in a manner that maximizes the development of new
photovoltaic generating facilities, to create a long-term,
low-income solar marketplace throughout this State, to
integrate, through interaction with stakeholders, with
existing energy efficiency initiatives, and to minimize
administrative costs. The Illinois Solar for All Program
shall be implemented in a manner that seeks to minimize
administrative costs, and maximize efficiencies and
synergies available through coordination with similar
initiatives, including the Adjustable Block program
described in subparagraphs (K) through (M) of paragraph
(1) of subsection (c) of Section 1-75, energy efficiency
programs, job training programs, and community action
agencies. The Agency shall strive to ensure that projects
incentivized renewable energy credits procured through the
Illinois Solar for All Program and each of its subprograms
are purchased from projects across the breadth of
low-income and environmental justice communities in
Illinois, including both urban and rural communities, are
not concentrated in a few communities, and do not exclude
particular low-income or environmental justice
communities. The Agency shall include a description of its
proposed approach to the design, administration,
implementation and evaluation of the Illinois Solar for
All Program, as part of the long-term renewable resources

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procurement plan authorized by subsection (c) of Section
1-75 of this Act, and the program shall be designed to grow
the low-income solar market. The Agency or utility, as
applicable, shall purchase renewable energy credits or
equivalent amount in the form of an upfront rebate from
the (i) photovoltaic distributed renewable energy
generation projects and (ii) community solar projects that
are procured under procurement processes authorized by the
long-term renewable resources procurement plans approved
by the Commission.
The Illinois Solar for All Program shall include the
program offerings described in subparagraphs (A) through
(E) of this paragraph (2), which the Agency shall
implement through contracts with third-party providers
and, subject to appropriation, pay the approximate amounts
identified using monies available in the Illinois Power
Agency Renewable Energy Resources Fund. Each contract that
provides for the installation of solar facilities shall
provide that the solar facilities will produce energy and
economic benefits, at a level determined by the Agency to
be reasonable, for the participating low-income customers.
The monies available in the Illinois Power Agency
Renewable Energy Resources Fund and not otherwise
committed to contracts executed under subsection (i) of
this Section, as well as, in the case of the programs
described under subparagraphs (A) through (E) of this

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paragraph (2), funding authorized pursuant to subparagraph
(O) of paragraph (1) of subsection (c) of Section 1-75 of
this Act, shall initially be allocated among the programs
described in this paragraph (2), as follows: 35% of these
funds shall be allocated to programs described in
subparagraphs (A) and (E) of this paragraph (2), 40% of
these funds shall be allocated to programs described in
subparagraph (B) of this paragraph (2), and 25% of these
funds shall be allocated to programs described in
subparagraph (C) of this paragraph (2). The allocation of
funds among subparagraphs (A), (B), (C), and (E) of this
paragraph (2) may be changed if the Agency, after
receiving input through a stakeholder process, determines
incentives in subparagraphs (A), (B), (C), or (E) of this
paragraph (2) have not been adequately subscribed to fully
utilize available Illinois Solar for All Program funds.
Contracts that will be paid with funds in the Illinois
Power Agency Renewable Energy Resources Fund shall be
executed by the Agency. Contracts that will be paid with
funds collected by an electric utility shall be executed
by the electric utility.
Contracts under the Illinois Solar for All Program
shall include an approach, as set forth in the long-term
renewable resources procurement plans, to ensure the
wholesale market value of the energy is credited to
participating low-income customers or organizations and to

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ensure tangible economic benefits flow directly to program
participants, except in the case of low-income
multi-family housing where the low-income customer does
not directly pay for energy. Priority shall be given to
projects that demonstrate meaningful involvement of
low-income community members in designing the initial
proposals. Acceptable proposals to implement projects must
demonstrate the applicant's ability to conduct initial
community outreach, education, and recruitment of
low-income participants in the community. Projects must
include job training opportunities if available, with the
specific level of trainee usage to be determined through
the Agency's long-term renewable resources procurement
plan, and the Illinois Solar for All Program Administrator
shall coordinate with the job training programs described
in paragraph (1) of subsection (a) of Section 16-108.12 of
the Public Utilities Act and in the Energy Transition Act.
The Agency shall make every effort to ensure that
small and emerging businesses, particularly those located
in low-income and environmental justice communities, are
able to participate in the Illinois Solar for All Program.
These efforts may include, but shall not be limited to,
proactive support from the program administrator,
different or preferred access to subprograms and
administrator-identified customers or grassroots
education provider-identified customers, and different

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incentive levels. The Agency shall report on progress and
barriers to participation of small and emerging businesses
in the Illinois Solar for All Program at least once a year.
The report shall be made available on the Agency's website
and, in years when the Agency is updating its long-term
renewable resources procurement plan, included in that
Plan.
(A) Low-income single-family and small multifamily
solar incentive. This program will provide incentives
to low-income customers, either directly or through
solar providers, to increase the participation of
low-income households in photovoltaic on-site
distributed generation at residential buildings
containing one to 4 units. Companies participating in
this program that install solar panels shall commit to
hiring job trainees for a portion of their low-income
installations, and an administrator shall facilitate
partnering the companies that install solar panels
with entities that provide solar panel installation
job training. It is a goal of this program that a
minimum of 25% of the incentives for this program be
allocated to projects located within environmental
justice communities. Contracts entered into under this
paragraph may be entered into with an entity that will
develop and administer the program and shall also
include contracts for renewable energy credits from

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the photovoltaic distributed generation or an
equivalent amount as an upfront rebate that is the
subject of the program, as set forth in the long-term
renewable resources procurement plan. Additionally:
(i) The Agency shall reserve a portion of this
program for projects that promote energy
sovereignty through ownership of projects by
low-income households, not-for-profit
organizations providing services to low-income
households, affordable housing owners, community
cooperatives, or community-based limited liability
companies providing services to low-income
households. Projects that feature energy ownership
should ensure that local people have control of
the project and reap benefits from the project
over and above energy bill savings. The Agency may
consider the inclusion of projects that promote
ownership over time or that involve partial
project ownership by communities, as promoting
energy sovereignty. Incentives for projects that
promote energy sovereignty may be higher than
incentives for equivalent projects that do not
promote energy sovereignty under this same
program.
(ii) Through its long-term renewable resources
procurement plan, the Agency shall consider

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additional program and contract requirements to
ensure faithful compliance by applicants
benefiting from preferences for projects
designated to promote energy sovereignty. The
Agency shall make every effort to enable solar
providers already participating in the Adjustable
Block Program under subparagraph (K) of paragraph
(1) of subsection (c) of Section 1-75 of this Act,
and particularly solar providers developing
projects under item (i) of subparagraph (K) of
paragraph (1) of subsection (c) of Section 1-75 of
this Act to easily participate in the Low-Income
Distributed Generation Incentive program described
under this subparagraph (A), and vice versa. This
effort may include, but shall not be limited to,
utilizing similar or the same application systems
and processes, similar or the same forms and
formats of communication, and providing active
outreach to companies participating in one program
but not the other. The Agency shall report on
efforts made to encourage this cross-participation
in its long-term renewable resources procurement
plan.
(B) Low-Income Community Solar Project Initiative.
Incentives shall be offered to low-income customers,
either directly or through developers, to increase the

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participation of low-income subscribers of community
solar projects. The developer of each project shall
identify its partnership with community stakeholders
regarding the location, development, and participation
in the project, provided that nothing shall preclude a
project from including an anchor tenant that does not
qualify as low-income. Companies participating in this
program that develop or install solar projects shall
commit to hiring job trainees for a portion of their
low-income installations, and an administrator shall
facilitate partnering the companies that install solar
projects with entities that provide solar installation
and related job training. It is a goal of this program
that a minimum of 25% of the incentives for this
program be allocated to community photovoltaic
projects in environmental justice communities. The
Agency shall reserve a portion of this program for
projects that promote energy sovereignty through
ownership of projects by low-income households,
not-for-profit organizations providing services to
low-income households, affordable housing owners, or
community-based limited liability companies providing
services to low-income households. Projects that
feature energy ownership should ensure that local
people have control of the project and reap benefits
from the project over and above energy bill savings.

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The Agency may consider the inclusion of projects that
promote ownership over time or that involve partial
project ownership by communities, as promoting energy
sovereignty. Incentives for projects that promote
energy sovereignty may be higher than incentives for
equivalent projects that do not promote energy
sovereignty under this same program. Contracts entered
into under this paragraph may be entered into with
developers and shall also include contracts for
renewable energy credits related to the program.
(C) Incentives for non-profits and public
facilities. Under this program funds shall be used to
support on-site photovoltaic distributed renewable
energy generation devices to serve the load associated
with not-for-profit customers and to support
photovoltaic distributed renewable energy generation
that uses photovoltaic technology to serve the load
associated with public sector customers taking service
at public buildings. Companies participating in this
program that develop or install solar projects shall
commit to hiring job trainees for a portion of their
low-income installations, and an administrator shall
facilitate partnering the companies that install solar
projects with entities that provide solar installation
and related job training. Through its long-term
renewable resources procurement plan, the Agency shall

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consider additional program and contract requirements
to ensure faithful compliance by applicants benefiting
from preferences for projects designated to promote
energy sovereignty. It is a goal of this program that
at least 25% of the incentives for this program be
allocated to projects located in environmental justice
communities. Contracts entered into under this
paragraph may be entered into with an entity that will
develop and administer the program or with developers
and shall also include contracts for renewable energy
credits or upfront rebates related to the program.
(D) (Blank).
(E) Low-income large multifamily solar incentive.
This program shall provide incentives to low-income
customers, either directly or through solar providers,
to increase the participation of low-income households
in photovoltaic on-site distributed generation at
residential buildings with 5 or more units. Companies
participating in this program that develop or install
solar projects shall commit to hiring job trainees for
a portion of their low-income installations, and an
administrator shall facilitate partnering the
companies that install solar projects with entities
that provide solar installation and related job
training. It is a goal of this program that a minimum
of 25% of the incentives for this program be allocated

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to projects located within environmental justice
communities. The Agency shall reserve a portion of
this program for projects that promote energy
sovereignty through ownership of projects by
low-income households, not-for-profit organizations
providing services to low-income households,
affordable housing owners, or community-based limited
liability companies providing services to low-income
households. Projects that feature energy ownership
should ensure that local people have control of the
project and reap benefits from the project over and
above energy bill savings. The Agency may consider the
inclusion of projects that promote ownership over time
or that involve partial project ownership by
communities, as promoting energy sovereignty.
Incentives for projects that promote energy
sovereignty may be higher than incentives for
equivalent projects that do not promote energy
sovereignty under this same program.
The requirement that a qualified person, as defined in
paragraph (1) of subsection (i) of this Section, install
photovoltaic devices does not apply to the Illinois Solar
for All Program described in this subsection (b).
In addition to the programs outlined in paragraphs (A)
through (E), the Agency and other parties may propose
additional programs through the Long-Term Renewable

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Resources Procurement Plan developed and approved under
paragraph (5) of subsection (b) of Section 16-111.5 of the
Public Utilities Act. Additional programs may target
market segments not specified above and may also include
incentives targeted to increase the uptake of
nonphotovoltaic technologies by low-income customers,
including energy storage paired with photovoltaics, if the
Commission determines that the Illinois Solar for All
Program would provide greater benefits to the public
health and well-being of low-income residents through also
supporting that additional program versus supporting
programs already authorized.
(3) Costs associated with the Illinois Solar for All
Program and its components described in paragraph (2) of
this subsection (b), including, but not limited to, costs
associated with procuring experts, consultants, and the
program administrator referenced in this subsection (b)
and related incremental costs, costs related to income
verification and facilitating customer participation in
the program, and costs related to the evaluation of the
Illinois Solar for All Program, may be paid for using
monies in the Illinois Power Agency Renewable Energy
Resources Fund, and funds allocated pursuant to
subparagraph (O) of paragraph (1) of subsection (c) of
Section 1-75, but the Agency or program administrator
shall strive to minimize costs in the implementation of

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the program. The Agency or contracting electric utility
shall purchase renewable energy credits or fund upfront
rebates from generation that is the subject of a contract
under subparagraphs (A) through (E) of paragraph (2) of
this subsection (b), and may pay for such renewable energy
credits or rebates through an upfront payment per
installed kilowatt of nameplate capacity paid once the
device is interconnected at the distribution system level
of the interconnecting utility and verified as energized.
The IPA shall determine in its long-term renewable
resources procurement plan described in subsection (c) of
Section 1-75 of this Act and Section 16-111.5 of the
Public Utilities Act if renewable energy credits or an
upfront rebate directly to consumers is most effective at
achieving the aims of the Illinois Solar for All program
with the most efficient use of funds. If the Agency
chooses to continue with renewable energy credits,
payments Payments for renewable energy credits shall be in
exchange for all renewable energy credits generated by the
system during the first 15 years of operation and shall be
structured to overcome barriers to participation in the
solar market by the low-income community. The incentives
provided for in this Section may be implemented through
the pricing of renewable energy credits where the prices
paid for the credits are higher than the prices from
programs offered under subsection (c) of Section 1-75 of

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this Act to account for the additional capital necessary
to successfully access targeted market segments. The
Agency or contracting electric utility shall retire or
track any renewable energy credits purchased under this
program and the credits shall count toward the obligation
under subsection (c) of Section 1-75 of this Act for the
electric utility to which the project is interconnected,
if applicable.
The Agency shall direct that up to 5% of the funds
available under the Illinois Solar for All Program to
community-based groups and other qualifying organizations
to assist in community-driven education efforts related to
the Illinois Solar for All Program, including general
energy education, job training program outreach efforts,
and other activities deemed to be qualified by the Agency.
Grassroots education funding shall not be used to support
the marketing by solar project development firms and
organizations, unless such education provides equal
opportunities for all applicable firms and organizations.
The Agency shall direct up to 25% of the funds
currently allocated to subparagraphs (A), (C), and (E) of
this subsection (b) towards grants, rebates, or incentives
designed to incentivize energy storage paired with
photovoltaic distributed renewable energy generation
devices. This new incentive program for income-qualified
storage may be titled "Illinois Storage for All". The

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Illinois Storage for All program shall be available to
current and future participants of the Low-income single
family and small multifamily subprogram described in
subparagraph (A), the subprogram for non-profit and public
facilities described in subparagraph (C), and the
Low-income large multifamily solar incentive described in
subparagraph (E) of paragraph (2). The program shall be
designed to support community energy resilience, disaster
preparedness, and energy bill reductions, particularly for
residents of low-income and environmental justice
communities. The Agency shall propose the funding amount,
structure, and details of this storage incentive program
in their long-term renewable resources procurement plan
described in subsection (c) of Section 1-75 of this Act
and Section 16-111.5 of the Public Utilities Act. Prior to
filing the proposed program in their long-term renewable
resources procurement plan, the Agency shall separately
engage stakeholders in program design including, but not
limited to, members of the Illinois Commission on
Environmental Justice described in Section 10 of the
Environmental Justice Act, representatives of Approved
Vendors participating in the Illinois Solar for All
Program, representatives of community-based
organizations, and members of the Illinois Solar for All
Stakeholder Advisory Group.
(4) The Agency shall, consistent with the requirements

HB3779 - 89 - LRB104 11172 AAS 21254 b
of this subsection (b), propose the Illinois Solar for All
Program terms, conditions, and requirements, including the
prices to be paid for renewable energy credits or rebates,
and which prices may be determined through a formula,
through the development, review, and approval of the
Agency's long-term renewable resources procurement plan
described in subsection (c) of Section 1-75 of this Act
and Section 16-111.5 of the Public Utilities Act. In the
course of the Commission proceeding initiated to review
and approve the plan, including the Illinois Solar for All
Program proposed by the Agency, a party may propose an
additional low-income solar or solar incentive program, or
modifications to the programs proposed by the Agency, and
the Commission may approve an additional program, or
modifications to the Agency's proposed program, if the
additional or modified program more effectively maximizes
the benefits to low-income customers after taking into
account all relevant factors, including, but not limited
to, the extent to which a competitive market for
low-income solar has developed. Following the Commission's
approval of the Illinois Solar for All Program, the Agency
or a party may propose adjustments to the program terms,
conditions, and requirements, including the price offered
to new systems, to ensure the long-term viability and
success of the program. The Commission shall review and
approve any modifications to the program through the plan

HB3779 - 90 - LRB104 11172 AAS 21254 b
revision process described in Section 16-111.5 of the
Public Utilities Act.
(5) The Agency shall issue a request for
qualifications for a third-party program administrator or
administrators to administer all or a portion of the
Illinois Solar for All Program. The third-party program
administrator shall be chosen through a competitive bid
process based on selection criteria and requirements
developed by the Agency, including, but not limited to,
experience in administering low-income energy programs and
overseeing statewide clean energy or energy efficiency
services. If the Agency retains a program administrator or
administrators to implement all or a portion of the
Illinois Solar for All Program, each administrator shall
periodically submit reports to the Agency and Commission
for each program that it administers, at appropriate
intervals to be identified by the Agency in its long-term
renewable resources procurement plan, provided that the
reporting interval is at least quarterly. The third-party
program administrator may be, but need not be, the same
administrator as for the Adjustable Block program
described in subparagraphs (K) through (M) of paragraph
(1) of subsection (c) of Section 1-75. The Agency, through
its long-term renewable resources procurement plan
approval process, shall also determine if individual
subprograms of the Illinois Solar for All Program are

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better served by a different or separate Program
Administrator.
The third-party administrator's responsibilities
shall also include facilitating placement for graduates of
Illinois-based renewable energy-specific job training
programs, including the Clean Jobs Workforce Network
Program and the Illinois Climate Works Preapprenticeship
Program administered by the Department of Commerce and
Economic Opportunity and programs administered under
Section 16-108.12 of the Public Utilities Act. To increase
the uptake of trainees by participating firms, the
administrator shall also develop a web-based clearinghouse
for information available to both job training program
graduates and firms participating, directly or indirectly,
in Illinois solar incentive programs. The program
administrator shall also coordinate its activities with
entities implementing electric and natural gas
income-qualified energy efficiency programs, including
customer referrals to and from such programs, and connect
prospective low-income solar customers with any existing
deferred maintenance programs where applicable.
(6) The long-term renewable resources procurement plan
shall also provide for an independent evaluation of the
Illinois Solar for All Program. At least every 2 years,
the Agency shall select an independent evaluator to review
and report on the Illinois Solar for All Program and the

HB3779 - 92 - LRB104 11172 AAS 21254 b
performance of the third-party program administrator of
the Illinois Solar for All Program. The evaluation shall
be based on objective criteria developed through a public
stakeholder process. The process shall include feedback
and participation from Illinois Solar for All Program
stakeholders, including participants and organizations in
environmental justice and historically underserved
communities. The report shall include a summary of the
evaluation of the Illinois Solar for All Program based on
the stakeholder developed objective criteria. The report
shall include the number of projects installed; the total
installed capacity in kilowatts; the average cost per
kilowatt of installed capacity to the extent reasonably
obtainable by the Agency; the number of jobs or job
opportunities created; economic, social, and environmental
benefits created; and the total administrative costs
expended by the Agency and program administrator to
implement and evaluate the program. The report shall be
delivered to the Commission and posted on the Agency's
website, and shall be used, as needed, to revise the
Illinois Solar for All Program. The Commission shall also
consider the results of the evaluation as part of its
review of the long-term renewable resources procurement
plan under subsection (c) of Section 1-75 of this Act.
(7) If additional funding for the programs described
in this subsection (b) is available under subsection (k)

HB3779 - 93 - LRB104 11172 AAS 21254 b
of Section 16-108 of the Public Utilities Act, then the
Agency shall submit a procurement plan to the Commission
no later than September 1, 2018, that proposes how the
Agency will procure programs on behalf of the applicable
utility. After notice and hearing, the Commission shall
approve, or approve with modification, the plan no later
than November 1, 2018.
(8) As part of the development and update of the
long-term renewable resources procurement plan authorized
by subsection (c) of Section 1-75 of this Act, the Agency
shall plan for: (A) actions to refer customers from the
Illinois Solar for All Program to electric and natural gas
income-qualified energy efficiency programs, and vice
versa, with the goal of increasing participation in both
of these programs; (B) effective procedures for data
sharing, as needed, to effectuate referrals between the
Illinois Solar for All Program and both electric and
natural gas income-qualified energy efficiency programs,
including sharing customer information directly with the
utilities, as needed and appropriate; and (C) efforts to
identify any existing deferred maintenance programs for
which prospective Solar for All Program customers may be
eligible and connect prospective customers for whom
deferred maintenance is or may be a barrier to solar
installation to those programs.
As used in this subsection (b), "low-income households"

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means persons and families whose income does not exceed 80% of
area median income, adjusted for family size and revised every
5 years.
For the purposes of this subsection (b), the Agency shall
define "environmental justice community" based on the
methodologies and findings established by the Agency and the
Administrator for the Illinois Solar for All Program in its
initial long-term renewable resources procurement plan and as
updated by the Agency and the Administrator for the Illinois
Solar for All Program as part of the long-term renewable
resources procurement plan update.
(b-5) After the receipt of all payments required by
Section 16-115D of the Public Utilities Act, no additional
funds shall be deposited into the Illinois Power Agency
Renewable Energy Resources Fund unless directed by order of
the Commission.
(b-10) After the receipt of all payments required by
Section 16-115D of the Public Utilities Act and payment in
full of all contracts executed by the Agency under subsections
(b) and (i) of this Section, if the balance of the Illinois
Power Agency Renewable Energy Resources Fund is under $5,000,
then the Fund shall be inoperative and any remaining funds and
any funds submitted to the Fund after that date, shall be
transferred to the Supplemental Low-Income Energy Assistance
Fund for use in the Low-Income Home Energy Assistance Program,
as authorized by the Energy Assistance Act.

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(b-15) The prevailing wage requirements set forth in the
Prevailing Wage Act apply to each project that is undertaken
pursuant to one or more of the programs of incentives and
initiatives described in subsection (b) of this Section and
for which a project application is submitted to the program
after the effective date of this amendatory Act of the 103rd
General Assembly, except (i) projects that serve single-family
or multi-family residential buildings and (ii) projects with
an aggregate capacity of less than 100 kilowatts that serve
houses of worship. The Agency shall require verification that
all construction performed on a project by the renewable
energy credit delivery contract holder, its contractors, or
its subcontractors relating to the construction of the
facility is performed by workers receiving an amount for that
work that is greater than or equal to the general prevailing
rate of wages as that term is defined in the Prevailing Wage
Act, and the Agency may adjust renewable energy credit prices
to account for increased labor costs.
In this subsection (b-15), "house of worship" has the
meaning given in subparagraph (Q) of paragraph (1) of
subsection (c) of Section 1-75.
(c) (Blank).
(d) (Blank).
(e) All renewable energy credits procured using monies
from the Illinois Power Agency Renewable Energy Resources Fund
shall be permanently retired.

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(f) The selection of one or more third-party program
managers or administrators, the selection of the independent
evaluator, and the procurement processes described in this
Section are exempt from the requirements of the Illinois
Procurement Code, under Section 20-10 of that Code.
(g) All disbursements from the Illinois Power Agency
Renewable Energy Resources 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 or
by the person or persons designated by the Director for that
purpose. The Comptroller is authorized to draw the warrant
upon vouchers so signed. The Treasurer shall accept all
warrants so signed and shall be released from liability for
all payments made on those warrants.
(h) The Illinois Power Agency Renewable Energy Resources
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 any funds from this
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 this Section.
(h-5) The Agency may assess fees to each bidder to recover
the costs incurred in connection with a procurement process
held under this Section. Fees collected from bidders shall be
deposited into the Renewable Energy Resources Fund.

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(i) Supplemental procurement process.
(1) Within 90 days after June 30, 2014 (the effective
date of Public Act 98-672), the Agency shall develop a
one-time supplemental procurement plan limited to the
procurement of renewable energy credits, if available,
from new or existing photovoltaics, including, but not
limited to, distributed photovoltaic generation. Nothing
in this subsection (i) requires procurement of wind
generation through the supplemental procurement.
Renewable energy credits procured from new
photovoltaics, including, but not limited to, distributed
photovoltaic generation, under this subsection (i) must be
procured from devices installed by a qualified person. In
its supplemental procurement plan, the Agency shall
establish contractually enforceable mechanisms for
ensuring that the installation of new photovoltaics is
performed by a qualified person.
For the purposes of this paragraph (1), "qualified
person" means a person who performs installations of
photovoltaics, including, but not limited to, distributed
photovoltaic generation, and who: (A) has completed an
apprenticeship as a journeyman electrician from a United
States Department of Labor registered electrical
apprenticeship and training program and received a
certification of satisfactory completion; or (B) does not
currently meet the criteria under clause (A) of this

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paragraph (1), but is enrolled in a United States
Department of Labor registered electrical apprenticeship
program, provided that the person is directly supervised
by a person who meets the criteria under clause (A) of this
paragraph (1); or (C) has obtained one of the following
credentials in addition to attesting to satisfactory
completion of at least 5 years or 8,000 hours of
documented hands-on electrical experience: (i) a North
American Board of Certified Energy Practitioners (NABCEP)
Installer Certificate for Solar PV; (ii) an Underwriters
Laboratories (UL) PV Systems Installer Certificate; (iii)
an Electronics Technicians Association, International
(ETAI) Level 3 PV Installer Certificate; or (iv) an
Associate in Applied Science degree from an Illinois
Community College Board approved community college program
in renewable energy or a distributed generation
technology.
For the purposes of this paragraph (1), "directly
supervised" means that there is a qualified person who
meets the qualifications under clause (A) of this
paragraph (1) and who is available for supervision and
consultation regarding the work performed by persons under
clause (B) of this paragraph (1), including a final
inspection of the installation work that has been directly
supervised to ensure safety and conformity with applicable
codes.

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For the purposes of this paragraph (1), "install"
means the major activities and actions required to
connect, in accordance with applicable building and
electrical codes, the conductors, connectors, and all
associated fittings, devices, power outlets, or
apparatuses mounted at the premises that are directly
involved in delivering energy to the premises' electrical
wiring from the photovoltaics, including, but not limited
to, to distributed photovoltaic generation.
The renewable energy credits procured pursuant to the
supplemental procurement plan shall be procured using up
to $30,000,000 from the Illinois Power Agency Renewable
Energy Resources Fund. The Agency shall not plan to use
funds from the Illinois Power Agency Renewable Energy
Resources Fund in excess of the monies on deposit in such
fund or projected to be deposited into such fund. The
supplemental procurement plan shall ensure adequate,
reliable, affordable, efficient, and environmentally
sustainable renewable energy resources (including credits)
at the lowest total cost over time, taking into account
any benefits of price stability.
To the extent available, 50% of the renewable energy
credits procured from distributed renewable energy
generation shall come from devices of less than 25
kilowatts in nameplate capacity. Procurement of renewable
energy credits from distributed renewable energy

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generation devices shall be done through multi-year
contracts of no less than 5 years. The Agency shall create
credit requirements for counterparties. In order to
minimize the administrative burden on contracting
entities, the Agency shall solicit the use of third
parties to aggregate distributed renewable energy. These
third parties shall enter into and administer contracts
with individual distributed renewable energy generation
device owners. An individual distributed renewable energy
generation device owner shall have the ability to measure
the output of his or her distributed renewable energy
generation device.
In developing the supplemental procurement plan, the
Agency shall hold at least one workshop open to the public
within 90 days after June 30, 2014 (the effective date of
Public Act 98-672) and shall consider any comments made by
stakeholders or the public. Upon development of the
supplemental procurement plan within this 90-day period,
copies of the supplemental procurement plan shall be
posted and made publicly available on the Agency's and
Commission's websites. All interested parties shall have
14 days following the date of posting to provide comment
to the Agency on the supplemental 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 supplemental

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procurement plan, accompanied by specific alternative
wording or proposals. All comments shall be posted on the
Agency's and Commission's websites. Within 14 days
following the end of the 14-day review period, the Agency
shall revise the supplemental procurement plan as
necessary based on the comments received and file its
revised supplemental procurement plan with the Commission
for approval.
(2) Within 5 days after the filing of the supplemental
procurement plan at the Commission, any person objecting
to the supplemental procurement plan shall 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 supplemental procurement plan
within 90 days after the filing of the supplemental
procurement plan by the Agency.
(3) The Commission shall approve the supplemental
procurement plan of renewable energy credits to be
procured from new or existing photovoltaics, including,
but not limited to, distributed photovoltaic generation,
if the Commission determines that it will ensure adequate,
reliable, affordable, efficient, and environmentally
sustainable electric service in the form of renewable
energy credits at the lowest total cost over time, taking
into account any benefits of price stability.

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(4) The supplemental procurement process under this
subsection (i) shall include each of the following
components:
(A) Procurement administrator. The Agency may
retain a procurement administrator in the manner set
forth in item (2) of subsection (a) of Section 1-75 of
this Act to conduct the supplemental procurement or
may elect to use the same procurement administrator
administering the Agency's annual procurement under
Section 1-75.
(B) Procurement monitor. The procurement monitor
retained by the Commission pursuant to Section
16-111.5 of the Public Utilities Act shall:
(i) monitor interactions among the procurement
administrator and bidders and suppliers;
(ii) monitor and report to the Commission on
the progress of the supplemental procurement
process;
(iii) provide an independent confidential
report to the Commission regarding the results of
the procurement events;
(iv) assess compliance with the procurement
plan approved by the Commission for the
supplemental procurement process;
(v) preserve the confidentiality of supplier
and bidding information in a manner consistent

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with all applicable laws, rules, regulations, and
tariffs;
(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;
(vii) consult with the procurement
administrator regarding the development and use of
benchmark criteria, standard form contracts,
credit policies, and bid documents; and
(viii) perform, with respect to the
supplemental procurement process, any other
procurement monitor duties specifically delineated
within subsection (i) of this Section.
(C) Solicitation, prequalification, 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 Agency's and

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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 item (D) of this paragraph (4). The
procurement administrator shall then identify and
register bidders to participate in the procurement
event.
(D) Standard contract forms and credit terms and
instruments. The procurement administrator, in
consultation with the Agency, 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 as well as include any
applicable State of Illinois terms and conditions that
are required for contracts entered into by an agency
of the State of Illinois. Standard credit terms and
instruments that meet generally accepted industry
practices shall be similarly developed. Contracts for
new photovoltaics shall include a provision attesting
that the supplier will use a qualified person for the
installation of the device pursuant to paragraph (1)
of subsection (i) of this Section. The procurement
administrator shall make available to the Commission

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all written comments it receives on the contract
forms, credit terms, or instruments. If the
procurement administrator cannot reach agreement with
the parties 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. 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.
(E) Requests for proposals; competitive
procurement process. The procurement administrator
shall design and issue requests for proposals to
supply renewable energy credits in accordance with the
supplemental procurement plan, as approved by the
Commission. The requests 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, provided,
however, that no bid shall be accepted if it exceeds
the benchmark developed pursuant to item (F) of this
paragraph (4).
(F) Benchmarks. Benchmarks for each product to be
procured shall be developed by the procurement
administrator in consultation with Commission staff,

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the Agency, and the procurement monitor for use in
this supplemental procurement.
(G) A plan for implementing contingencies in the
event of supplier default, Commission rejection of
results, or any other cause.
(5) 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 within 2 business days after receipt of the
reports.
(6) Within 3 business days after the Commission
decision approving the results of a procurement event, the

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Agency shall enter into binding contractual arrangements
with the winning suppliers using the standard form
contracts.
(7) The names of the successful bidders and the
average of the winning bid prices for each contract type
and for each contract term shall be made available to the
public within 2 days after the supplemental procurement
event. The Commission, the procurement monitor, the
procurement administrator, the 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 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.
(8) The supplemental procurement provided in this
subsection (i) shall not be subject to the requirements
and limitations of subsections (c) and (d) of this
Section.
(9) Expenses incurred in connection with the
procurement process held pursuant to this Section,

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including, but not limited to, the cost of developing the
supplemental procurement plan, the procurement
administrator, procurement monitor, and the cost of the
retirement of renewable energy credits purchased pursuant
to the supplemental procurement shall be paid for from the
Illinois Power Agency Renewable Energy Resources Fund. The
Agency shall enter into an interagency agreement with the
Commission to reimburse the Commission for its costs
associated with the procurement monitor for the
supplemental procurement process.
(Source: P.A. 102-662, eff. 9-15-21; 103-188, eff. 6-30-23;
103-605, eff. 7-1-24.)
(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,
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

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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. Beginning on the effective
date of this amendatory Act of the 104th General Assembly, the
Planning and Procurement Bureau shall develop plans and
processes for the procurement of energy storage in accordance
with the requirements of Section 1-93 of this Act and Section
16-111.5 of the Public Utilities Act. 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
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

HB3779 - 110 - LRB104 11172 AAS 21254 b
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
Utilities Act. In order to qualify an expert or expert
consulting firm must have:
(A) direct previous experience assembling

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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
firm must have:
(A) direct previous experience administering a
large-scale competitive procurement process;

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(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
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

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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
proposals submitted and shall award contracts of up to 5
years to those selected.
(6) The Agency shall select an expert or expert

HB3779 - 114 - LRB104 11172 AAS 21254 b
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.
(1)(A) The Agency shall develop a long-term renewable
resources procurement plan that shall include procurement
programs and competitive procurement events necessary to

HB3779 - 115 - LRB104 11172 AAS 21254 b
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),
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

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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
hydropower facilities.
For the delivery year beginning June 1, 2017, the
procurement plan shall attempt to include, subject to the

HB3779 - 117 - LRB104 11172 AAS 21254 b
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
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

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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
wind and solar projects by the end of delivery year
2030 such that the goals in subparagraph (B) of this
paragraph (1) are met entirely by procurements of

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renewable energy credits from new wind and
photovoltaic projects. Of that amount, to the extent
possible, the Agency shall procure 45% from wind and
hydropower projects and 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.
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,

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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.
(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

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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
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

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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
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. 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
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

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(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), 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).
Except as the maximum dollar amount of renewable resources
to be procured may be otherwise increased by the
Commission in the Agency's long-term renewable resources
procurement plan described in subparagraph (A) of this
paragraph (1) based on the Commission finding that the
expected long-term cost savings to eligible retail
customers from the procurements enabled by the increased
maximum dollar amount exceed the additional costs, such
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

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customers in connection with electric service to no more
than 4.25% of the amount paid per kilowatthour by those
customers during 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.
All costs incurred under such contracts shall be fully
recoverable by the electric utility as provided in this
Section.
(F) If the limitation on the amount of renewable
energy resources procured in subparagraph (E) of this
paragraph (1) prevents the Agency from meeting all of the

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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
solicit 15-year contracts for delivery of 1,000,000

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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
utility-scale solar projects and brownfield site

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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
of the 102nd General Assembly in quantities necessary

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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
delivery contract value shall be paid in full,

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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
the order in which they appear on the

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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
energy credits generated by the project during

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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
community renewable generation projects

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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
waitlisted project eligible for selection

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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
applicant firms no later than 90 days after

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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).
Contract instruments used for this

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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
with that project of greater than 30 cents

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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
nameplate capacity. Renewable energy credit prices

HB3779 - 137 - LRB104 11172 AAS 21254 b
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
that is approved as of the effective date of this

HB3779 - 138 - LRB104 11172 AAS 21254 b
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).
(v) Upon the effective date of this amendatory Act

HB3779 - 139 - LRB104 11172 AAS 21254 b
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
established under subparagraph (E) for indexed

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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
of the estimated annual cost of the contracts for

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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.
(vi) All procurements under this subparagraph (G),

HB3779 - 142 - LRB104 11172 AAS 21254 b
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).
(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
this subparagraph (H) if an alternative retail electric

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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
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
alternative retail electric supplier.
(iii) The alternative retail electric supplier

HB3779 - 144 - LRB104 11172 AAS 21254 b
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.
For delivery years beginning June 1, 2019 and
each year thereafter, the maximum amount of

HB3779 - 145 - LRB104 11172 AAS 21254 b
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%
value shall apply to each delivery year.
If the requirements set forth in items (i) through

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(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
in the health, safety, and welfare of its residents,
including but not limited to minimizing sulfur dioxide,

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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
its residents based on the public interest criteria
described above. For the purposes of this Section,

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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
this subsection (c) if they are sourced from a generating
unit whose costs were being recovered through rates

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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
costs of these units are recovered. As long as a
generating unit or an identifiable portion of a generating

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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, 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.
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

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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
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

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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
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

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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) the Agency shall select projects on a
first-come, first-serve basis, however the Agency
may suggest additional methods to prioritize
projects that are submitted at the 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

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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
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

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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
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

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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
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

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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
(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

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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
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

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under 5,000 kilowatts or photovoltaic community
renewable generation projects, from applicants that
are 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) 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

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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
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.

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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
renewable energy credits under items (i) through (vi) of
subparagraph (K) of this paragraph (1) shall otherwise be

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subject to the following contract and payment terms:
(i) (Blank).
(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
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

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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
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

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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
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

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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
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

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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
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

HB3779 - 167 - LRB104 11172 AAS 21254 b
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
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

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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
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

HB3779 - 169 - LRB104 11172 AAS 21254 b
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
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

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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
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.

HB3779 - 171 - LRB104 11172 AAS 21254 b
(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
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

HB3779 - 172 - LRB104 11172 AAS 21254 b
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
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

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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
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

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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
$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

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(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
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

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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
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

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projects;
(iv) all new photovoltaic community renewable
energy facilities that qualify for item (iii) of
subparagraph (K) of this paragraph (1);
(v) all new community driven community
photovoltaic projects 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 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 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;

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(ix) all new, modernized, or retooled
hydropower facilities.
(2) Renewable energy credits procured from new
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

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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
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

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shall take effect in the delivery year commencing June 1,
2023.
(1) For the purposes of this subparagraph:
"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;

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(ii) be sourced from one or more renewable
energy generating facilities that comply with the
geographic requirements as set forth in
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

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energy customer;
(vi) be sourced from new utility-scale wind
projects or new utility-scale solar projects; and
(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

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participation in the self-direct renewable portfolio
standard compliance program exceeds availability, the
Agency shall ensure participation is evenly split
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

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under contracts for new utility-scale wind and new
utility-scale solar entered for each delivery year
after the large energy customer begins retiring
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.

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The Commission must approve the self-direct credit
amount by June 1, 2023 and June 1 of each delivery year
thereafter.
(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;

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(iii) certification that the contract or
contracts for new renewable energy resources are
long-term contracts with term lengths of at least
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

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renewable energy credits and do not notify the Agency
are ineligible for continued participation in the
self-direct renewable portfolio standard compliance
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

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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
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

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subsection (c), to the extent feasible and consistent with
State and federal law, the renewable energy credit
procurements, Adjustable Block solar program, and
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

HB3779 - 190 - LRB104 11172 AAS 21254 b
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
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

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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
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

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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
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

HB3779 - 193 - LRB104 11172 AAS 21254 b
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 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

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facility or by previous employment experience
performing the employee's particular work skill or
function.
(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

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power plant workers.
(H) The applicant commits to enter into a contract
or contracts for the applicable duration to provide
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

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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
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

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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
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

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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
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

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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
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

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under-delivery of renewable energy credits within
reasonable ranges during each 12-month period and penalty,
default, and enforcement provisions for failure of the
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

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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
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

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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
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

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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
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;

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(4) the owner of the electric generating
facility has not been selected by the Agency
pursuant to this subsection (c-5) of this Section
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,

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with such date subject to adjustment as needed due
to any delays in completing the grant contracting
process, in finalizing interconnection agreements
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;

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(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
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

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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
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

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accept all written warrants so signed and shall be
released from liability for all payments made on those
warrants.
(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

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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
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

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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
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

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industry.
(D) The applicant or owner may submit a revised or
updated plan to the Commission from time to time as
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

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disproportionately experienced negative public health
outcomes. Further, it is the purpose of this subsection to
ensure that this equity accountability system is successful in
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

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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
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

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shall require a compliance plan at the time of
application.
(B) Halfway through each delivery year, the Agency
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

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compliance and shall allow continued access to
procurement programs upon an approved vendor or
designee demonstrating compliance.
(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

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practicable, entities participating in competitive
procurements shall also be required to meet all the equity
accountability requirements for approved vendors and their
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

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paragraph (1) of subsection (c) and in meeting the
minimum equity standards of this subsection (c-10).
(D) A process for certifying equity eligible
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

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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
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

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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
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

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empower the Agency and other State actors to remedy racial
discrimination in Illinois' clean energy economy as
effectively and expediently as possible, including through
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

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Illinois' clean energy economy. The Agency may hire
consultants and experts to conduct the disparity and
availability study, with the retention of those
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

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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
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.
(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
necessary for the purpose of achieving the purpose of

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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
limited to, contacts for suppliers, vendors, or

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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
placement rates of trainees; and

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(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
action plan and achieve compliance with the minimum equity

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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
subject to Commission review and approval.

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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
electric service includes without limitation amounts paid

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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
during the year ending May 31, 2012 or 2% of the amount

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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
electric utility subject to this Section shall execute a

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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
structure consisting of 45% equity and 55% debt,

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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
for electricity delivered under such sourcing

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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
(iv) be considered pre-existing contracts in

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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
subsection (d);

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(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;
(ii) provide that utilities shall maintain

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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
the facility that have been captured and

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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
designation as a clean coal facility if the

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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
determine the justness, reasonableness, and

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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
delivered to the facility busbar;

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(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
agreement with the initial clean coal facility shall not

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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
residential and small business customers over the life

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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
Commission shall, within 90 days of such enactment,

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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
associated with sequestration of carbon dioxide

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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,
maintenance contracts, chemicals, catalysts,

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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
initial clean coal facility.

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(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,
the contract price from which the reference price is

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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
than 100,000 retail customers in this State that

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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:
(A) Those zero emission facilities that intend to

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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 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 "necessary" means, for
purposes of this item (iii), that the costs could

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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 megawatthour
basis. However, to ensure that the procurement remains
affordable to retail customers in this State if
electricity prices increase, the price in an

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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 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
megawatthour shall increase by $1 per
megawatthour, and continue to increase by an
additional $1 per megawatthour each delivery year
thereafter.
(ii) Baseline market price index: The baseline
market price index for the consecutive 12-month
period ending May 31, 2016 is $31.40 per
megawatthour, which is based on the sum of (aa)

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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
during the calendar year immediately preceding
that delivery year to produce a single energy

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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
June 1, 2020, and each year thereafter,
the projected capacity price shall be

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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
the provisions of this paragraph (1) and shall provide
that winning bids shall be selected based on public

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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
State and their independent market monitors.
Upon publishing of the zero emission standard

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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
successful bidders:
(i) identify how the winning bids satisfy the

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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
Protection Agency eGrid subregion carbon
dioxide emission rate and the U.S. Interagency

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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
credits from photovoltaic distributed
generation projects in procurement events

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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
the payments to be made under each contract for the
next delivery year based on the market price index for

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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
reasonable efforts, it has been unable to
overcome. In such event, the zero emission

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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
such resource would not undertake.
(iv) A zero emission facility shall be

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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,
the contractual volume receiving payments in such year
shall be reduced for all retail customers based on the

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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
paragraph (2), no subsequent rate impact determinations
shall be made and no adjustments to those contract amounts

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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
payments received by the supplier over the relevant period
exceed the Average ZEC Payment, then the supplier shall

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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
(d-5).
If the subtraction yields a negative number, then the

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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
to avoid and not increase carbon emissions from electric
generation sources while continuing to ensure affordable,

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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
an independent audit which provided a detailed assessment
of the financial condition of the Illinois nuclear fleet

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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
residents.
(2) As used in this subsection:

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"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
serving at least 3,000,000 retail customers in the State,
seek to procure contracts for no more than approximately

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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
subparagraph (E) of paragraph (1) of subsection (d-5)
of this Section or made impracticable as a result of

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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
anticipated tax credits, and any other direct
federal support.

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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
applicable.
(ii) Contracts for carbon mitigation credits shall

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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
delivery years, and then any subsequent delivery
years unless the PJM Interconnection, LLC applies

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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
calculation performed under item (iii) of this
subparagraph (C) for a given delivery year results in

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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
to $33.43 per megawatt-hour.
(IV) For the delivery year beginning June 1,

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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
emission rate for 2020, and that a carbon-free energy
resource receiving payment for carbon mitigation

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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
ensure that the public interest criteria are applied to
the procurement. The Plan shall, to the extent practical

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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
carbon-free energy resources at prices that are within the
limits specified in this paragraph (3). As part of the

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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
gas emissions measured as the product of the
carbon-free energy resources' output over the

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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
the December 3, 2021 contract execution deadline.
Following the completion of such procurements, and

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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
set forth in Section 16-111.5 of the Public Utilities Act.
(g) The Agency shall assess fees to each affected utility

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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 3855/1-79 new)
Sec. 1-79. Planning and Procurement Bureau modeling.
Planning and Procurement Bureau shall establish an Office of
Energy Modeling that shall have the following duties and
responsibilities:

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(a) The Office of Energy Modeling shall develop resource
adequacy analysis, impacts analysis, scenario planning,
sensitivity analysis, and program analysis pursuant to the
requirements of subsection (o) of Section 9.15 of the
Environmental Protection Act.
(b) The Office of Energy Modeling shall develop and
maintain a database of Illinois' electric generation,
transmission, distribution, and supporting infrastructure
using data from sources, including, but not limited to:
(1) the Federal Energy Regulatory Commission, the
United States Energy Information Administration, the
United States Department of Energy, and the United States
Environmental Protection Agency, or other similar sources;
(2) Illinois State agencies, including the Illinois
Power Agency, the Illinois Commerce Commission, the
Department of Commerce and Economic Opportunity, and the
Illinois Environmental Protection Agency;
(3) Regional Transmission Organizations, Independent
System Operators, or any other entity authorized by the
Federal Energy Regulatory Commission to promote the
reliability and adequacy of bulk power transmission;
(4) electric utilities, municipal utilities, and
electric cooperatives; and
(5) other public and private data sources as
necessary.
The database shall be published and maintained online in

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machine-readable formats in regular, distinct, numbered
versions. To the extent that sensitive datasets cannot be made
public because they contain information meeting the Federal
Energy Regulatory Commission's definition of either "critical
electric infrastructure information" or "critical energy
infrastructure information" under 18 CFR 388.113, meeting the
definition of "trade secret" under Section 2 of the Illinois
Trade Secrets Act, or otherwise containing confidential or
sensitive materials, the Office of Energy Modeling shall both
publish simulated datasets designed to maintain the
statistical patterns and relationships present in the original
dataset and allow secure and confidential access to the
sensitive data for qualified entities, such as utilities,
academics, or advocates under confidentiality agreements and
to the extent permitted by law.
(c) The Office of Energy Modeling shall perform energy
modeling studies and develop or supervise development of
production cost, capacity expansion, and resource adequacy
models for Illinois. The Agency shall develop models using
open source energy modeling tools and open data. This
development will occur in public, using a web-based interface
to open source version control software, and the models will
be published with permissive open-source licenses. The Office
of Energy Modeling shall establish a transparent modeling
process that accepts and considers public comment. All studies
funded, commissioned, or undertaken by the Office of Energy

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Modeling shall publish the inputs, assumptions, parameters,
constraints, and forecasts associated with the study, in
machine-readable file formats compatible with the software
used to produce the study, such that the Office of Energy
Modeling or another stakeholder could recreate the study
results using the same modeling software, regardless of
whether that software is open source or proprietary.
(d) The Office of Energy Modeling shall conduct reviews of
external energy system reports, modeling, and studies of
Illinois-specific and regional resource adequacy produced by
regional transmission organizations, reliability
organizations, and the federal government and shall produce
executive summaries and analyses of the key findings, methods,
and implications of the reports and studies. The Office of
Energy Modeling shall also, from time to time and within
reason, be available to provide insights on energy system
modeling and analysis to the Governor, members of the General
Assembly, other state agencies, units of local government, and
the public.
(e) The Office of Energy Modeling may obtain outside
resources, including, but not limited to, consultants or other
external entities, to assist in the performance of its duties.
Any work performed using outside resources, including work by
consultants or other external entities, must be conducted
openly and transparently using open-source tools and data
whenever possible and shall contribute to the open source

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models and datasets maintained by the Office of Energy
Modeling.
(20 ILCS 3855/1-93 new)
Sec. 1-93. Energy Storage Procurement Program.
(a) The General Assembly finds that:
(1) The health, welfare, and prosperity of all
Illinois residents require that the State of Illinois act
to reduce existing and avoid new carbon emissions from
electric generation sources while continuing to ensure
clean, affordable, and reliable electricity for all
residents.
(2) Energy storage resources are necessary for the
State's transition to 100% clean energy, to reduce
reliance on carbon-intensive energy resources, for
transitioning to a fully decarbonized electricity sector,
and to help ensure health and welfare of the State's
residents.
(3) Illinois is likely to require substantial energy
storage resources that will play a key role in allowing
the State's power grid to accommodate reduced operations
from fossil fuel power plants pursuant to emission limit
requirements scheduled to occur in 2030, 2035, and beyond,
as set forth in Section 9.15(o) of the Environmental
Protection Act.
(b) The Agency shall conduct an initial forward

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procurement of utility-scale energy storage resources not to
exceed 1,500 megawatts. The IPA shall develop a confidential
benchmark and shall have solicited, received, and opened
sealed bids for such initial procurement not later than August
26, 2025. This initial forward procurement shall utilize the
procurement process, structure, and contract terms as
recommended in the staff of the Illinois Commerce Commission's
report submitted pursuant to Section 16-135(g) of the Public
Utilities Act.
(c) Within 270 days after the effective date of this
amendatory Act of the 104th General Assembly, the Agency shall
develop an energy storage procurement plan that shall include
procurement programs and competitive procurement events
necessary to meet the goals set forth in this Section. The
energy storage procurement plan and any subsequent revisions
shall be subject to review and approval by the Commission
under Section 16-111.5 of the Public Utilities Act. The Agency
shall endeavor to coordinate submission of the energy storage
procurement plan and any subsequent revisions simultaneous
with long-term renewable resources procurement plans pursuant
to Sections 1-56(b) and 1-75(c) of this Act and Section
16-111.5 of the Public Utilities Act.
(d) The energy storage procurement plan shall develop
procurements and programs as necessary to achieve an initial
goal of having at least 3,000 megawatts of cumulative energy
storage capacity by 2030, of sufficient duration to qualify as

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a capacity resource, interconnected to or able to participate
in markets run by the Midcontinent Independent System
Operator, Inc., PJM Interconnection, LLC, or their respective
successors. The Agency may establish additional targets for
such capacity based on identified resource adequacy needs for
Midcontinent Independent System Operator, Inc., PJM
Interconnection, LLC, or their respective successors. The
Agency shall regularly assess, both prior to and after 2030,
whether procurement of additional amounts of energy storage
capacity is necessary to support achievement of the goals set
forth in Public Act 102-662 and shall include such proposals
in revisions to the energy storage procurement plan pursuant
to subsection (f) of this Section.
(e) The energy storage procurement plan shall take into
consideration the following:
(1) requirements for interconnection milestones
sufficient to meet operational date targets including the
evaluation of projects proposed to augment or replace
existing resources at existing interconnection sites;
(2) requirements for demonstrated experience in
bringing utility-scale energy storage facilities to
commercial readiness, aggregating behind-the-meter demand
and storage resources, or equivalent expertise;
(3) requirements for demonstration of binding site
control sufficient for proposed energy storage facilities;
(4) the development of contract, payment, and

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performance structures that enable project development and
finance;
(5) the need to protect retail customers from retail
rate impacts that may arise, including through the
reduction of the price paid under a contract, or
remittance by suppliers back to utilities, for a given
delivery year based on energy price and capacity price
indices;
(6) provisions for adjustments to contracts in the
event of unanticipated circumstances;
(7) operational requirements for energy storage
services contracted; and
(8) commitments of the energy storage systems to serve
Illinois resource adequacy needs, consistent with Illinois
critical resource adequacy needs as identified in the
resource adequacy study and resource planning process
described in subsection (o) of Section 9.15 of the
Environmental Protection Act, as well as any relevant
modeling performed by the Agency or related available
recommendations or findings of the North American Electric
Reliability Corporation, PJM Interconnection, LLC, and
Midcontinent Independent System Operator, Inc., or their
respective successors.
(f) The Agency shall review, and may revise on an
expedited basis, the energy storage procurement plan at least
every 2 years. Revisions to the energy storage procurement

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plan may address the following:
(1) updates to procurement targets as approved by the
Commission under the resource adequacy study and resource
planning process described in subsection (o) of Section
9.15 of the Environmental Protection Act or as otherwise
may be approved by the Commission in a revised energy
storage procurement plan;
(2) revisions to contract, payment, and performance
structures to ensure development, protect retail customers
from retail rate impacts, and address market and
technology changes insofar as the revisions do not affect
existing and active contracts; and
(3) other plan components as developed by the Agency.
(g) All procurements under this Section shall comply with
the geographic requirements in subparagraph (I) of paragraph
(1) of subsection (c) of Section 1-75, shall support energy
storage systems interconnected to the ComEd Zone of PJM
Interconnection, LLC, or Zone 4 of Midcontinent Independent
System Operator, Inc., or their respective successors, and
shall follow the procurement processes and procedures
described in this Section and Section 16-111.5 of the Public
Utilities Act.
(h) The Agency shall procure energy storage resources that
are cost-effective. The procurement administrator shall
establish confidential price benchmarks based on publicly
available data on regional technology and construction costs.

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Benchmarks shall reflect development, financing, and related
costs resulting from requirements imposed through the energy
storage procurement plan and other provisions of State law. As
used in this subsection, "cost-effective" means that the
energy storage resources procurement price, plus any projected
market revenue, does not exceed confidential benchmarks.
(i) Energy storage resources procured under this Section
must be from energy storage systems built by general
contractors that enter into a project labor agreement prior to
construction. The project labor agreement shall be filed with
the Agency in accordance with procedures established by the
Agency through its energy storage procurement plan. Any
information submitted to the Agency 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.
Each energy storage system shall be subject to the prevailing
wage requirements included in the Prevailing Wage Act. The
Agency shall require verification that all construction
performed on the energy storage system by the energy storage
resources delivery contract holder, its contractors, or its
subcontractors relating to construction of the energy storage

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system is performed by construction employees receiving an
amount for that work that is equal to or greater than the
general prevailing rate, as that term is used in Section 3 of
the Prevailing Wage Act.
(j) In order to advance 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, the Agency shall update its Equity
Accountability System and minimum equity standards established
under subsections (c-10), (c-15), (c-20), (c-25), and (c-30)
of Section 1-75 of this Act to include energy storage
resources procurements and programs, and include such
modifications in its energy storage procurement plan
submission to the Commission under Section 16-111.5 of the
Public Utilities Act.
(k) In order to promote the competitive development of
energy storage systems in furtherance of the State's interest
in the health, safety, and welfare of its residents, energy
storage resources shall not be eligible to be selected under
this Section if 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 energy storage resources
under this Section shall provide for the contract's

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termination if the costs of the energy storage system
supplying the energy storage resources 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
energy storage resources subsequently begin to be recovered
through rates regulated by this State or any other state or
states, the supplier of the energy storage resources must
return 110% of all payments received under the energy storage
resources procurement contract. Amounts returned under the
requirements of this subsection shall be refunded to the
respective ratepayers in the same proportion as the cost
allocation for the contract. 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, as a prerequisite to payment
for any energy storage resources procurement, 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 as required in this Section.
Section 105. The Counties Code is amended by adding
Division 5-46 as follows:

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(55 ILCS 5/Div. 5-46 heading new)
Division 5-46 Solar Bill of Rights
(55 ILCS 5/5-46005 new)
Sec. 5-46005. Definitions. As used in this Division:
"Low voltage solar powered device" means a piece of
equipment designed for a particular purpose, including, but
not limited to, doorbells, security systems and illumination
equipment, powered by a solar collector operating at less than
50 volts and located:
(1) entirely within the lot or parcel owned by the
property owner; or
(2) within a common area without being permanently
attached to common property.
"Solar energy " means radiant energy received from the sun
at wave lengths suitable for heat transfer, photosynthetic
use, or photovoltaic use.
"Solar collector" means:
(1) an assembly, structure, or design, including
passive elements, used for gathering, concentrating, or
absorbing direct and indirect solar energy, specially
designed for holding a substantial amount of useful
thermal energy and to transfer that energy to a gas,
solid, or liquid or to use that energy directly; or
(2) a mechanism that absorbs solar energy and converts

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it into electricity; or
(3) a mechanism or process used for gathering solar
energy through wind or thermal gradients; or
(4) a component used to transfer thermal energy to a
gas, solid, or liquid, or to convert it into electricity.
"Solar storage mechanism" means equipment or elements
(such as piping and transfer mechanisms, containers, heat
exchangers, batteries, or controls thereof, and gases, solids,
liquids, or combinations thereof) that are utilized for
storing solar energy, gathered by a solar collector, for
subsequent use.
"Solar energy system" means:
(1) a complete assembly, structure, or design of solar
collector or a solar storage mechanism that uses solar
energy for generating electricity or for heating or
cooling gases, solids, liquids, or other materials; and
(2) the design, materials, or elements of a system and
its maintenance, operation, and labor components, and the
necessary components, if any, of supplemental conventional
energy systems designed or constructed to interface with a
solar energy system.
(55 ILCS 5/5-46010 new)
Sec. 5-46010. Prohibitions. Notwithstanding any provision
of this Code or other provision of law, the adoption of any
ordinance or resolution, or exercise of any power, by a county

HB3779 - 295 - LRB104 11172 AAS 21254 b
which prohibits or has the effect of prohibiting the
installation of a solar energy system or low voltage solar
powered device is expressly prohibited.
(55 ILCS 5/5-46015 new)
Sec. 5-46015. Home rule. A home rule unit may not regulate
the Solar Bill of Rights in a manner more restrictive than the
regulation by the State under this Division. This Section is a
limitation under subsection (i) of Section 6 of Article VII of
the Illinois Constitution on the concurrent exercise by home
rule units of powers and functions exercised by the State.
(55 ILCS 5/5-46020 new)
Sec. 5-46020. Costs; attorney 's fees. In any litigation
arising under this Division or involving the application of
this Division, the prevailing party shall be entitled to costs
and reasonable attorney's fees.
(55 ILCS 5/5-46025 new)
Sec. 5-46025. Inapplicability; applicability.
(a) This Division shall not apply to any building that:
(1) is greater than 60 feet in height; or
(2) has a shared roof and is subject to a homeowners'
association, common interest community association, or
condominium unit owners' association.
(b) Notwithstanding subsection (a) of this Section, this

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Division shall apply to any building with a shared roof:
(1) where the solar energy system is located entirely
within that portion of the shared roof owned and
maintained by the property owner;
(2) where all property owners sharing the shared roof
are in agreement to install a solar energy system; or
(3) to the extent this Division applies to low voltage
solar powered devices.
(c) As used in this Section, "shared roof" means any roof
that (i) serves more than one unit, including, but not limited
to, a contiguous roof serving adjacent units, or (ii) is part
of the common elements or common area.
Section 110. The Illinois Municipal Code is amended by
changing Sections 11-119.1-4 and 11-119.1-10 and by adding
Division 15.5 to Article 11 as follows:
(65 ILCS 5/Art. 11 Div. 15.5 heading new)
DIVISION. 15.5. SOLAR BILL OF RIGHTS
(65 ILCS 5/11-15.5-5 new)
Sec. 11-15.5-5. Definitions. As used in this Division:
"Low voltage solar powered device" means a piece of
equipment designed for a particular purpose, including, but
not limited to, doorbells, security systems and illumination
equipment, powered by a solar collector operating at less than

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50 volts and located:
(1) entirely within the lot or parcel owned by the
property owner; or
(2) within a common area without being permanently
attached to common property.
"Solar energy" means radiant energy received from the sun
at wave lengths suitable for heat transfer, photosynthetic
use, or photovoltaic use.
"Solar collector" means:
(1) an assembly, structure, or design, including
passive elements, used for gathering, concentrating, or
absorbing direct and indirect solar energy, specially
designed for holding a substantial amount of useful
thermal energy and to transfer that energy to a gas,
solid, or liquid or to use that energy directly; or
(2) a mechanism that absorbs solar energy and converts
it into electricity; or
(3) a mechanism or process used for gathering solar
energy through wind or thermal gradients; or
(4) a component used to transfer thermal energy to a
gas, solid, or liquid, or to convert it into electricity.
"Solar storage mechanism" means equipment or elements
(such as piping and transfer mechanisms, containers, heat
exchangers, batteries, or controls thereof, and gases, solids,
liquids, or combinations thereof) that are utilized for
storing solar energy, gathered by a solar collector, for

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subsequent use.
"Solar energy system" means:
(1) a complete assembly, structure, or design of solar
collector or a solar storage mechanism that uses solar
energy for generating electricity or for heating or
cooling gases, solids, liquids, or other materials; and
(2) the design, materials, or elements of a system and
its maintenance, operation, and labor components, and the
necessary components, if any, of supplemental conventional
energy systems designed or constructed to interface with a
solar energy system.
(65 ILCS 5/11-15.5-10 new)
Sec. 11-15.5-10. Prohibitions. Notwithstanding any
provision of this Code or other provision of law, the adoption
of any ordinance or resolution, or exercise of any power, by
municipality that prohibits or has the effect of prohibiting
the installation of a solar energy system or low voltage solar
powered device is expressly prohibited; provided however,
municipalities that own local electric distribution systems
may adopt and implement reasonable policies, not inconsistent
with Section 17-900 of the Public Utilities Act, regarding the
interconnection and use of solar energy systems.
(65 ILCS 5/11-15.5-15 new)
Sec. 11-15.5-15. Home rule. A home rule unit may not

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regulate the Solar Bill of Rights in a manner more restrictive
than the regulation by the State under this Division. This
Section is a limitation under subsection (i) of Section 6 of
Article VII of the Illinois Constitution on the concurrent
exercise by home rule units of powers and functions exercised
by the State.
(65 ILCS 5/11-15.5-20 new)
Sec. 11-15.5-20. Costs; attorney's fees. In any litigation
arising under this Division or involving the application of
this Division, the prevailing party shall be entitled to costs
and reasonable attorney's fees.
(65 ILCS 5/11-15.25 new)
Sec. 11-15.25. Inapplicability; applicability.
(a) This Division shall not apply to any building that:
(1) is greater than 60 feet in height; or
(2) has a shared roof and is subject to a homeowners'
association, common interest community association, or
condominium unit owners' association.
(b) Notwithstanding subsection (a) of this Section, this
Division shall apply to any building with a shared roof:
(1) where the solar energy system is located entirely
within that portion of the shared roof owned and
maintained by the property owner;
(2) where all property owners sharing the shared roof

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are in agreement to install a solar energy system; or
(3) to the extent this Division applies to low voltage
solar powered devices.
(c) As used in this Section, "shared roof" means any roof
that (i) serves more than one unit, including, but not limited
to, a contiguous roof serving adjacent units, or (ii) is part
of the common elements or common area.
(65 ILCS 5/11-119.1-4) (from Ch. 24, par. 11-119.1-4)
Sec. 11-119.1-4. Municipal Power Agencies.
A. Any 2 or more municipalities, contiguous or
noncontiguous, and which operate an electric utility system,
may form a municipal power agency by the execution of an agency
agreement authorized by an ordinance adopted by the governing
body of each municipality. The agency agreement may state:
(1) that the municipal power agency is created and
incorporated under the provisions of this Division as a
body politic and corporate, municipal corporation and unit
of local government of the State of Illinois;
(2) the name of the agency and the date of its
establishment;
(3) that names of the municipalities which have
adopted the agency agreement and constitute the initial
members of the municipal power agency;
(4) the names and addresses of the persons initially
appointed in the ordinances adopting the agency agreement

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to serve on the Board of Directors and act as the
representatives of the municipalities, respectively, in
the exercise of their powers as members;
(5) the limitations, if any, upon the terms of office
of the directors, provided that such directors shall
always be selected and vacancies in their offices declared
and filled by ordinances adopted by the governing body of
the respective municipalities;
(6) the location by city, village or incorporated town
in the State of Illinois of the principal office of the
municipal power agency;
(7) provisions for the disposition, division or
distribution of obligations, property and assets of the
municipal power agency upon dissolution; and
(8) any other provisions for regulating the business
of the municipal power agency or the conduct of its
affairs which may be agreed to by the member
municipalities, consistent with this Division, including,
without limitation, any provisions for weighted voting
among the member municipalities or by the directors.
B. The presiding officer of the Board of Directors of any
municipal power agency established pursuant to this Division
or such other officer selected by the Board of Directors,
within 3 months after establishment, shall file a certified
copy of the agency agreement and a list of the municipalities
which have adopted the agreement with the recorder of deeds of

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the county in which the principal office is located. The
recorder of deeds shall record this certified copy and list
and shall immediately transmit the certified copy and list to
the Secretary of State, together with his certificate of
recordation. The Secretary of State shall file these documents
and issue his certificate of approval over his signature and
the Great Seal of the State. The Secretary of State shall make
and keep a register of municipal power agencies established
under this Division.
C. Each municipality which becomes a member of the
municipal power agency shall appoint a representative to serve
on the Board of Directors, which representative may be a
member of the governing body of the municipality. Each
appointment shall be made by the mayor, or president, subject
to the confirmation of the governing body. The directors so
appointed shall hold office for a term of 3 years, or until a
successor has been duly appointed and qualified, except that
the directors first appointed shall determine by lot at their
initial meeting the respective directors which shall serve for
a term of one, 2 or 3 years from the date of that meeting. A
vacancy shall be filled for the balance of the unexpired term
in the same manner as the original appointment.
The Board of Directors is the corporate authority of the
municipal power agency and shall exercise all the powers and
manage and control all of the affairs and property of the
agency. The Board of Directors shall have full power to pass

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all necessary ordinances, resolutions, rules and regulations
for the proper management and conduct of the business of the
board, and for carrying into effect the objects for which the
agency was established.
At the initial meeting of the Board of Directors to be held
within 30 days after the date of establishment of the
municipal power agency, the directors shall elect from their
members a presiding officer to preside over the meetings of
the Board of Directors and an alternative presiding officer
and may elect an executive board. The Board of Directors shall
determine and designate in the agency's bylaws the titles for
the presiding officers. The directors shall also elect a
secretary and treasurer, who need not be directors. The board
may select such other officers, employees and agents as deemed
to be necessary, who need not be directors or residents of any
of the municipalities which are members of the municipal power
agency. The board may designate appropriate titles for all
other officers, employees, and agents. All persons selected by
the board shall hold their respective offices during the
pleasure of the board, and give such bond as may be required by
the board.
D. The bylaws of the municipal power agency, and any
amendments thereto, shall be adopted by the Board of Directors
by a majority vote (adjusted for weighted voting, if provided
in the Agency Agreement) to provide the following:
(1) the conditions and obligations of membership, if

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any;
(2) the manner and time of calling regular and special
meetings of the Board of Directors;
(3) the procedural rules of the Board of Directors;
(4) the composition, powers and responsibilities of
any committee or executive board;
(5) the rights and obligations of new members,
conditions for the termination of membership, including a
formula for the determination of required termination
payments, if any, and the disposition of rights and
obligations upon termination of membership; and
(6) such other rules or provisions for regulating the
affairs of the municipal power agency as the board shall
determine to be necessary.
E. Every municipal power agency shall maintain an office
in the State of Illinois to be known as its principal office.
When a municipal power agency desires to change the location
of such office, it shall file with the Secretary of State a
certificate of change of location, stating the new address and
the effective date of change. Meetings of the Board of
Directors may be held at any place within the State of
Illinois, designated by the Board of Directors, after notice.
Unless otherwise provided by the bylaws, an act of the
majority of the directors present at a meeting at which a
quorum is present is the act of the Board of Directors.
F. The Board of Directors shall hold at least one meeting

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each year for the election of officers and for the transaction
of any other business. Special meetings of the Board of
Directors may be called for any purpose upon written request
to the presiding officer of the Board of Directors or
secretary to call the meeting. Such officer shall give notice
of the meeting to be held not less than 10 days and not more
than 60 days after receipt of such request. Unless the bylaws
provide for a different percentage, a quorum for a meeting of
the Board of Directors is a majority of all members then in
office. All meetings of the board shall be held in compliance
with the provisions of "An Act in relation to meetings",
approved July 11, 1957, as amended.
G. The agency agreement may be amended as proposed at any
meeting of the Board of Directors for which notice, stating
the purpose, shall be given to each director and, unless the
bylaws prescribe otherwise, such amendment shall become
effective when ratified by ordinances adopted by a majority of
the governing bodies of the member municipalities. Each
amendment, duly certified, shall be recorded and filed in the
same manner as for the original agreement.
H. Each member municipality shall have full power and
authority, subject to the provisions of its charter and laws
regarding local finance, to appropriate money for the payment
of the expenses of the municipal power agency and of its
representative in exercising its functions as a member of the
municipal power agency.

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I. Any additional municipality which operates an electric
utility system may join the municipal power agency, or any
member municipality may withdraw therefrom consistent with the
bylaws of the municipal power agency, and upon payment of any
termination obligations as described in subsection D upon the
approval by ordinance adopted by the governing body of the
majority of the municipalities which are then members of the
municipal power agency. Any new member shall agree to assume
its proportionate share of the outstanding obligations of the
municipal power agency and any member permitted to withdraw
shall remain obligated to make payments under any outstanding
contract or agreement with the municipal power agency or to
comply with any exit or early termination provisions set forth
in that contract or agreement. Any such change in membership
shall be recorded and filed in the same manner as for the
original agreement.
J. Any 2 or more municipal power agencies organized
pursuant to this Division may consolidate to form a new
municipal power agency when approved by ordinance adopted by
the governing body of each municipality which is a member of
the respective municipal power agency and by the execution of
an agency agreement as provided in this Section.
(Source: P.A. 96-204, eff. 1-1-10.)
(65 ILCS 5/11-119.1-5.5 new)
Sec. 11-119.1-5.5. Agency records, budgets, and quarterly

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reports.
(a) A municipal power agency shall keep accurate accounts
and records of its assets, liabilities, revenues, and
expenditures in accordance with generally accepted accounting
principles. Such accounts and records shall include, but are
not limited to, depreciation, operating and maintenance
expenses for all generation and transmission assets, fuel
costs, cost and revenue from the purchase or sale of
environmental compliance credits, revenue from energy,
capacity, and ancillary market sales, all payments received
from member municipalities, membership dues or other payments
made to trade associations or industry organizations, and
lobbying expenditures. Such records shall be audited on an
annual basis by an independent auditor using generally
accepted auditing standards and shall include contents as set
forth in Section 8-8-5, and shall be filed with the
Comptroller as described by Section 8-8-7.
(b) A municipal power agency shall, on an annual basis,
prepare one-year and 5-year budgets that include all revenues
and expenses, including, but not limited to, those categories
described in subsection (a). As part of each one-year budget,
the municipal power agency shall include a report identifying
and explaining any variance from the previous annual budget of
5% or greater in any expenditure or revenue line item. Such
budgets shall be provided to member municipalities no less
than 60 days prior to any meeting of the municipal power agency

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during which action on the budget is or will be part of the
agency agenda.
(c) The municipal power agency shall post, on a publicly
available website, all one-year and 5-year budgets required
under subsection (b) and the annual audited financial
statements required under subsection (a).
(d) The municipal power agency shall make available, upon
request to any of its member municipalities, access to all
municipal power agency all records and accounts and all
financial information relating to ownership and operation of
agency assets and the generation, procurement, and delivery of
electricity to which the agency has access, including, but not
limited to, unit scheduling information, market revenue and
off-system sales data, and fuel and other variable cost
information. Such information shall be provided in a timely
manner and through reasonable means, and members shall be
permitted to make copies of any documents retained solely by
the agency. Such access shall be provided without regard to
any nondisclosure agreement that has been or may be adopted by
the municipal power agency.
(e) The municipal power agency shall prepare, on a
quarterly basis, a report to its member municipalities
describing all expenditures made for the purpose of lobbying,
as both terms are defined by Section 2 of the Lobbyist
Registration Act, and a brief summary of the topics and
positions on which lobbying activities were undertaken. Where

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the municipal power agency is a member of an organization or
trade association that expends some or all of membership dues
on lobbying activities, the municipal power agency shall
include in this report the amount of those membership dues,
what proportion of those dues were spent on lobbying
activities, and the topics and positions on which lobbying
activities were undertaken by the organization or trade
association of which the municipal power agency is a member.
(65 ILCS 5/11-119.1-10) (from Ch. 24, par. 11-119.1-10)
Sec. 11-119.1-10. Exercise of powers. A municipal power
agency may exercise any and all of the powers enumerated in
this Division, except the power of eminent domain, without the
consent and approval of the Illinois Commerce Commission. The
exercise of the power of eminent domain by a municipal power
agency shall be subject to the consent and approval of the
Illinois Commerce Commission in the same manner and to the
same extent as public utilities under the Public Utilities
Act, including the issuance of a certificate of public
convenience and necessity as provided for in Section 8-406 of
that Act. During the consideration of any petition for
authority to exercise the power of eminent domain the Illinois
Commerce Commission shall evaluate and give due consideration
to whether the project for which eminent domain is sought is
part of the preferred portfolio as described in subsection (d)
of Section 15 of the Municipal and Cooperative Electric

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Utility Planning and Transparency Act, or least cost plans for
procuring renewable resources as described in subsections (f)
and (g) of Section 20 of the Municipal and Cooperative
Electric Utility Planning and Transparency Act and to the
impact of the acquisition on farmlands in the State with the
goal of preserving the land to the fullest extent reasonably
possible.
(Source: P.A. 90-416, eff. 1-1-98.)
Section 115. The Public Utilities Act is amended by
changing Sections 3-105, 8-103B, 8-406, 8-406.1, 8-512, 9-229,
16-107.5, 16-108, 16-108.30, 16-111.5, 16-115A, 16-115D,
17-500, and 17-900 and by adding Sections 8-104B, 16-107.7A,
and 16-107.8 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 now or hereafter 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

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controls or seeks Commission approval to own or control 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;
(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

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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
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

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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;
(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.
(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

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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
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 5/8-103B)
Sec. 8-103B. Energy efficiency and demand-response
measures.
(a) It is the policy of the State that electric utilities
are required to use cost-effective energy efficiency and
demand-response measures to reduce delivery load. Requiring
investment in cost-effective energy efficiency and
demand-response measures will reduce direct and indirect costs
to consumers by decreasing environmental impacts and by
avoiding or delaying the need for new generation,
transmission, and distribution infrastructure. It serves the
public interest to allow electric utilities to recover costs

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

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

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

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

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

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

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

HB3779 - 322 - LRB104 11172 AAS 21254 b
2012 and ending December 31, 2017, shall be reduced each year,
as follows, and the applicable value shall be applied to and
count toward the utility's achievement of the cumulative
persisting annual savings goals set forth in subsection
(b-15):
(1) 5.8% deemed cumulative persisting annual savings
for the year ending December 31, 2018;
(2) 5.2% deemed cumulative persisting annual savings
for the year ending December 31, 2019;
(3) 4.5% deemed cumulative persisting annual savings
for the year ending December 31, 2020;
(4) 4.0% deemed cumulative persisting annual savings
for the year ending December 31, 2021;
(5) 3.5% deemed cumulative persisting annual savings
for the year ending December 31, 2022;
(6) 3.1% deemed cumulative persisting annual savings
for the year ending December 31, 2023;
(7) 2.8% deemed cumulative persisting annual savings
for the year ending December 31, 2024; and
(8) 2.5% deemed cumulative persisting annual savings
for the year ending December 31, 2025; and
(9) 2.3% deemed cumulative persisting annual savings
for the year ending December 31, 2026. ;
(10) 2.1% deemed cumulative persisting annual savings
for the year ending December 31, 2027;
(11) 1.8% deemed cumulative persisting annual savings

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

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

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

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establishing goals that increase by more or less than that
amount. Such a proceeding must be conducted in accordance with
the procedures described in subsection (f) of this Section. If
such a proceeding is initiated, the cumulative persisting
annual savings goals established by the Commission through
that proceeding shall reflect the Commission's best estimate
of the maximum amount of additional savings that are forecast
to be cost-effectively achievable unless such best estimates
would result in goals that represent less than 0.4 percentage
point annual increases in total cumulative persisting annual
savings. The Commission may only establish goals that
represent less than 0.4 percentage point annual increases in
cumulative persisting annual savings if it can demonstrate,
based on clear and convincing evidence and through independent
analysis, that 0.4 percentage point increases are not
cost-effectively achievable. The Commission shall inform its
decision based on an energy efficiency potential study that
conforms to the requirements of this Section.
(b-16) In 2027 and each year thereafter, each electric
utility subject to this Section shall achieve incremental
annual savings equal to 2.00% of the utility's average annual
electricity sales, from 2021 through 2023, to customers other
than those that have opted out of subsections (a) through (j)
of this Section under paragraph (1) of subsection (l) of this
Section. In this Section, "incremental annual savings" means
the total electric savings from all measures installed in a

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calendar year that will be realized within 12 months of each
measure's installation.
The 2.00% incremental annual savings requirement may be
reduced by 0.025 percentage points for every 1 percentage
point increase, above the 25% minimum specified in paragraph
(c) of this Section, in the portion of total efficiency
program spending that is on low-income or moderate income
efficiency programs. For the purposes of this section,
moderate income is defined as incomes between 80% of area
median income and 300% of the federal poverty limit. In no
event shall the incremental annual savings requirement be
reduced to a level less than 1.75%, even if the sum of
low-income spending and moderate income spending is greater
than 35% of total spending.
Each utility's incremental annual savings must be achieved
with an average savings life of at least 12 years. In no event
can more than one-fifth of the incremental annual savings
counted toward a utility's annual savings goal in any given
year be derived from efficiency measures with average savings
life of less than 5 years. Average savings life is defined as
the lifetime savings that would be realized as a result of a
utility's efficiency programs divided by the incremental
annual savings such programs produce. Average savings lives
may be shorter than the average operational lives of measures
installed if the measures do not produce savings in every year
in which they operate or if the savings that measures produce

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decline during their operational lives.
(b-20) Each electric utility subject to this Section may
include cost-effective voltage optimization measures in its
plans submitted under subsections (f) and (g) of this Section,
and the costs incurred by a utility to implement the measures
under a Commission-approved plan shall be recovered under the
provisions of Article IX or Section 16-108.5 of this Act. For
purposes of this Section, the measure life of voltage
optimization measures shall be 15 years. The measure life
period is independent of the depreciation rate of the voltage
optimization assets deployed. Utilities may claim savings from
voltage optimization on circuits for more than 15 years if
they can demonstrate that they have made additional
investments necessary to enable voltage optimization savings
to continue beyond 15 years. Such demonstrations must be
subject to the review of independent evaluation.
Within 270 days after June 1, 2017 (the effective date of
Public Act 99-906), an electric utility that serves less than
3,000,000 retail customers but more than 500,000 retail
customers in the State shall file a plan with the Commission
that identifies the cost-effective voltage optimization
investment the electric utility plans to undertake through
December 31, 2024. The Commission, after notice and hearing,
shall approve or approve with modification the plan within 120
days after the plan's filing and, in the order approving or
approving with modification the plan, the Commission shall

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adjust the applicable cumulative persisting annual savings
goals set forth in subsection (b-15) to reflect any amount of
cost-effective energy savings approved by the Commission that
is greater than or less than the following cumulative
persisting annual savings values attributable to voltage
optimization for the applicable year:
(1) 0.0% of cumulative persisting annual savings for
the year ending December 31, 2018;
(2) 0.17% of cumulative persisting annual savings for
the year ending December 31, 2019;
(3) 0.17% of cumulative persisting annual savings for
the year ending December 31, 2020;
(4) 0.33% of cumulative persisting annual savings for
the year ending December 31, 2021;
(5) 0.5% of cumulative persisting annual savings for
the year ending December 31, 2022;
(6) 0.67% of cumulative persisting annual savings for
the year ending December 31, 2023;
(7) 0.83% of cumulative persisting annual savings for
the year ending December 31, 2024; and
(8) 1.0% of cumulative persisting annual savings for
the year ending December 31, 2025 and all subsequent
years.
(b-25) In the event an electric utility jointly offers an
energy efficiency measure or program with a gas utility under
plans approved under this Section and Section 8-104 of this

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Act, the electric utility may continue offering the program,
including the gas energy efficiency measures, in the event the
gas utility discontinues funding the program. In that event,
the energy savings value associated with such other fuels
shall be converted to electric energy savings on an equivalent
Btu basis for the premises. However, the electric utility
shall prioritize programs for low-income residential customers
to the extent practicable. An electric utility may recover the
costs of offering the gas energy efficiency measures under
this subsection (b-25).
For those energy efficiency measures or programs that save
both electricity and other fuels but are not jointly offered
with a gas utility under plans approved under this Section and
Section 8-104 or not offered with an affiliated gas utility
under paragraph (6) of subsection (f) of Section 8-104 of this
Act, the electric utility may count savings of fuels other
than electricity toward the achievement of its annual savings
goal, and the energy savings value associated with such other
fuels shall be converted to electric energy savings on an
equivalent Btu basis at the premises.
In no event shall more than 10% of each year's applicable
annual total savings requirement as defined in paragraph (7.5)
of subsection (g) of this Section, or more than 10% of each
year's incremental annual savings as defined in subsection
(b-16), be met through savings of fuels other than
electricity. If the weighted average total annual spending on

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efficiency programs by natural gas utilities with service
territories that overlap with an electric utility exceeds $50
per residential customer served by the natural gas utilities,
the limit on the amount of efficiency savings of fuels other
than electricity that can be counted toward the electric
utility's incremental annual savings requirement as defined in
subsection (b-16) shall be reduced from 20% to 15%.
(b-27) Beginning in 2022, an electric utility may offer
and promote measures that electrify space heating, water
heating, cooling, drying, cooking, industrial processes, and
other building and industrial end uses that would otherwise be
served by combustion of fossil fuel at the premises, provided
that the electrification measures reduce total energy
consumption at the premises. The electric utility may count
the reduction in energy consumption at the premises toward
achievement of its annual savings goals. The reduction in
energy consumption at the premises shall be calculated as the
difference between: (A) the reduction in Btu consumption of
fossil fuels as a result of electrification, converted to
kilowatt-hour equivalents by dividing by 3,412 Btus per
kilowatt hour; and (B) the increase in kilowatt hours of
electricity consumption resulting from the displacement of
fossil fuel consumption as a result of electrification. An
electric utility may recover the costs of offering and
promoting electrification measures under this subsection
(b-27).

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At least 33% of all such costs must be for supporting
installation of electrification measures through programs
exclusively targeted to low-income households. This 33%
requirement may be reduced if the utility can demonstrate that
it is not possible to achieve that level of low-income
electrification spending, while supporting programs for
non-low-income residential and business electrification,
because of limitations regarding the number of low-income
households in its service territory that would be able to meet
program eligibility requirements set forth in the multi-year
energy efficiency plan. If the 33% low-income electrification
spending requirement is reduced, the utility must prioritize
support of low-income electrification in housing that meets
program eligibility requirements over electrification spending
on non-low-income residential or business customers.
The ratio of spending on electrification measures targeted
to low-income, multifamily buildings to spending on
electrification measures targeted to low-income, single-family
buildings shall be designed to achieve levels of
electrification savings from each building type that are
approximately proportional to the magnitude of cost-effective
electrification savings potential in each building type.
In no event shall electrification savings counted toward
each year's applicable annual total savings requirement, as
defined in paragraph (7.5) of subsection (g) of this Section,
or counted toward each year's incremental annual savings, as

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defined in paragraph (b-16) of this Section, be greater than:
(1) 5% per year for each year from 2022 through 2025;
(1.5) 10% per year for 2026; and
(2) 15% per year for 2027 and all subsequent years.
10% per year for each year from 2026 through 2029; and
(3) 15% per year for 2030 and all subsequent years.
In addition, a minimum of 25% of all electrification savings
counted toward a utility's applicable annual total savings
requirement must be from electrification of end uses in
low-income housing. The limitations on electrification savings
that may be counted toward a utility's annual savings goals
are separate from and in addition to the subsection (b-25)
limitations governing the counting of the other fuel savings
resulting from efficiency measures and programs.
As part of the annual informational filing to the
Commission that is required under paragraph (9) of subsection
(g) of this Section, each utility shall identify the specific
electrification measures offered under this subsection (b-27);
the quantity of each electrification measure that was
installed by its customers; the average total cost, average
utility cost, average reduction in fossil fuel consumption,
and average increase in electricity consumption associated
with each electrification measure; the portion of
installations of each electrification measure that were in
low-income single-family housing, low-income multifamily
housing, non-low-income single-family housing, non-low-income

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multifamily housing, commercial buildings, and industrial
facilities; and the quantity of savings associated with each
measure category in each customer category that are being
counted toward the utility's applicable annual total savings
requirement or the utility's incremental annual savings as
defined in subsection (b-16). Prior to installing an
electrification measure, the utility shall provide a customer
with an estimate of the impact of the new measure on the
customer's average monthly electric bill and total annual
energy expenses.
(c) Electric utilities shall be responsible for overseeing
the design, development, and filing of energy efficiency plans
with the Commission and may, as part of that implementation,
outsource various aspects of program development and
implementation. A minimum of 10%, for electric utilities that
serve more than 3,000,000 retail customers in the State, and a
minimum of 7%, for electric utilities that serve less than
3,000,000 retail customers but more than 500,000 retail
customers in the State, of the utility's entire portfolio
funding level for a given year shall be used to procure
cost-effective energy efficiency measures from units of local
government, municipal corporations, school districts, public
housing, and community college districts, provided that a
minimum percentage of available funds shall be used to procure
energy efficiency from public housing, which percentage shall
be equal to public housing's share of public building energy

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consumption.
The utilities shall also implement energy efficiency
measures targeted at low-income households, which, for
purposes of this Section, shall be defined as households at or
below 80% of area median income, and expenditures to implement
the measures shall be no less than 25% of total energy
efficiency program spending approved by the Commission
pursuant to review of plans filed under paragraph (f) of this
Section $40,000,000 per year for electric utilities that serve
more than 3,000,000 retail customers in the State and no less
than $13,000,000 per year for electric utilities that serve
less than 3,000,000 retail customers but more than 500,000
retail customers in the State. The ratio of spending on
efficiency programs targeted at low-income multifamily
buildings to spending on efficiency programs targeted at
low-income single-family buildings shall be designed to
achieve levels of savings from each building type that are
approximately proportional to the magnitude of cost-effective
lifetime savings potential in each building type. Investment
in low-income whole-building weatherization programs shall
constitute a minimum of 80% of a utility's total budget
specifically dedicated to serving low-income customers.
The utilities shall work to bundle low-income energy
efficiency offerings with other programs that serve low-income
households to maximize the benefits going to these households.
The utilities shall market and implement low-income energy

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efficiency programs in coordination with low-income assistance
programs, the Illinois Solar for All Program, and
weatherization whenever practicable. The program implementer
shall walk the customer through the enrollment process for any
programs for which the customer is eligible. The utilities
shall also pilot targeting customers with high arrearages,
high energy intensity (ratio of energy usage divided by home
or unit square footage), or energy assistance programs with
energy efficiency offerings, and then track reduction in
arrearages as a result of the targeting. This targeting and
bundling of low-income energy programs shall be offered to
both low-income single-family and multifamily customers
(owners and residents).
The utilities shall invest in health and safety measures
appropriate and necessary for comprehensively weatherizing a
home or multifamily building, and shall implement a health and
safety fund of at least 15% of the total income-qualified
weatherization budget that shall be used for the purpose of
making grants for technical assistance, construction,
reconstruction, improvement, or repair of buildings to
facilitate their participation in the energy efficiency
programs targeted at low-income single-family and multifamily
households. These funds may also be used for the purpose of
making grants for technical assistance, construction,
reconstruction, improvement, or repair of the following
buildings to facilitate their participation in the energy

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efficiency programs created by this Section: (1) buildings
that are owned or operated by registered 501(c)(3) public
charities; and (2) day care centers, day care homes, or group
day care homes, as defined under 89 Ill. Adm. Code Part 406,
407, or 408, respectively.
Each electric utility shall assess opportunities to
implement cost-effective energy efficiency measures and
programs through a public housing authority or authorities
located in its service territory. If such opportunities are
identified, the utility shall propose such measures and
programs to address the opportunities. Expenditures to address
such opportunities shall be credited toward the minimum
procurement and expenditure requirements set forth in this
subsection (c).
Implementation of energy efficiency measures and programs
targeted at low-income households should be contracted, when
it is practicable, to independent third parties that have
demonstrated capabilities to serve such households, with a
preference for not-for-profit entities and government agencies
that have existing relationships with or experience serving
low-income communities in the State.
Each electric utility shall develop and implement
reporting procedures that address and assist in determining
the amount of energy savings that can be applied to the
low-income procurement and expenditure requirements set forth
in this subsection (c). Each electric utility shall also track

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the types and quantities or volumes of insulation and air
sealing materials, and their associated energy saving
benefits, installed in energy efficiency programs targeted at
low-income single-family and multifamily households.
The electric utilities shall participate in a low-income
energy efficiency accountability committee ("the committee"),
which will directly inform the design, implementation, and
evaluation of the low-income and public-housing energy
efficiency programs. The committee shall be comprised of the
electric utilities subject to the requirements of this
Section, the gas utilities subject to the requirements of
Section 8-104 of this Act, the utilities' low-income energy
efficiency implementation contractors, nonprofit
organizations, community action agencies, advocacy groups,
State and local governmental agencies, public-housing
organizations, and representatives of community-based
organizations, especially those living in or working with
environmental justice communities and BIPOC communities. The
committee shall be composed of 2 geographically differentiated
subcommittees: one for stakeholders in northern Illinois and
one for stakeholders in central and southern Illinois. The
subcommittees shall meet together at least twice per year.
There shall be one statewide leadership committee led by
and composed of community-based organizations that are
representative of BIPOC and environmental justice communities
and that includes equitable representation from BIPOC

HB3779 - 339 - LRB104 11172 AAS 21254 b
communities. The leadership committee shall be composed of an
equal number of representatives from the 2 subcommittees. The
subcommittees shall address specific programs and issues, with
the leadership committee convening targeted workgroups as
needed. The leadership committee may elect to work with an
independent facilitator to solicit and organize feedback,
recommendations and meeting participation from a wide variety
of community-based stakeholders. If a facilitator is used,
they shall be fair and responsive to the needs of all
stakeholders involved in the committee.
All committee meetings must be accessible, with rotating
locations if meetings are held in-person, virtual
participation options, and materials and agendas circulated in
advance.
There shall also be opportunities for direct input by
committee members outside of committee meetings, such as via
individual meetings, surveys, emails and calls, to ensure
robust participation by stakeholders with limited capacity and
ability to attend committee meetings. Committee meetings shall
emphasize opportunities to bundle and coordinate delivery of
low-income energy efficiency with other programs that serve
low-income communities, such as the Illinois Solar for All
Program and bill payment assistance programs. Meetings shall
include educational opportunities for stakeholders to learn
more about these additional offerings, and the committee shall
assist in figuring out the best methods for coordinated

HB3779 - 340 - LRB104 11172 AAS 21254 b
delivery and implementation of offerings when serving
low-income communities. The committee shall directly and
equitably influence and inform utility low-income and
public-housing energy efficiency programs and priorities.
Participating utilities shall implement recommendations from
the committee whenever possible.
Participating utilities shall track and report how input
from the committee has led to new approaches and changes in
their energy efficiency portfolios. This reporting shall occur
at committee meetings and in quarterly energy efficiency
reports to the Stakeholder Advisory Group and Illinois
Commerce Commission, and other relevant reporting mechanisms.
Participating utilities shall also report on relevant equity
data and metrics requested by the committee, such as energy
burden data, geographic, racial, and other relevant
demographic data on where programs are being delivered and
what populations programs are serving.
The Illinois Commerce Commission shall oversee and have
relevant staff participate in the committee. The committee
shall have a budget of 0.25% of each utility's entire
efficiency portfolio funding for a given year. The budget
shall be overseen by the Commission. The budget shall be used
to provide grants for community-based organizations serving on
the leadership committee, stipends for community-based
organizations participating in the committee, grants for
community-based organizations to do energy efficiency outreach

HB3779 - 341 - LRB104 11172 AAS 21254 b
and education, and relevant meeting needs as determined by the
leadership committee. The education and outreach shall
include, but is not limited to, basic energy efficiency
education, information about low-income energy efficiency
programs, and information on the committee's purpose,
structure, and activities.
(d) Notwithstanding any other provision of law to the
contrary, a utility providing approved energy efficiency
measures and, if applicable, demand-response measures in the
State shall be permitted to recover all reasonable and
prudently incurred costs of those measures from all retail
customers, except as provided in subsection (l) of this
Section, as follows, provided that nothing in this subsection
(d) permits the double recovery of such costs from customers:
(1) The utility may recover its costs through an
automatic adjustment clause tariff filed with and approved
by the Commission. The tariff shall be established outside
the context of a general rate case. Each year the
Commission shall initiate a review to reconcile any
amounts collected with the actual costs and to determine
the required adjustment to the annual tariff factor to
match annual expenditures. 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

HB3779 - 342 - LRB104 11172 AAS 21254 b
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) A utility may recover its costs through an energy
efficiency formula rate approved by the Commission under a
filing under subsections (f) and (g) of this Section,
which shall specify the cost components that form the
basis of the rate charged to customers with sufficient
specificity to operate in a standardized manner and be
updated annually with transparent information that
reflects the utility's actual costs to be recovered during
the applicable rate year, which is the period beginning
with the first billing day of January and extending
through the last billing day of the following December.
The energy efficiency formula rate shall be implemented
through a tariff filed with the Commission under
subsections (f) and (g) of this Section that is consistent
with the provisions of this paragraph (2) and that shall
be applicable to all delivery services customers. The
Commission shall conduct an investigation of the tariff in
a manner consistent with the provisions of this paragraph
(2), subsections (f) and (g) of this Section, and the
provisions of Article IX of this Act to the extent they do
not conflict with this paragraph (2). The energy
efficiency formula rate approved by the Commission shall

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remain in effect at the discretion of the utility and
shall do the following:
(A) Provide for the recovery of the utility's
actual costs incurred under this Section that are
prudently incurred and reasonable in amount consistent
with Commission practice and law. The sole fact that a
cost differs from that incurred in a prior calendar
year or that an investment is different from that made
in a prior calendar year shall not imply the
imprudence or unreasonableness of that cost or
investment.
(B) Reflect the utility's actual year-end capital
structure for the applicable calendar year, excluding
goodwill, subject to a determination of prudence and
reasonableness consistent with Commission practice and
law. 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, a participating electric
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.
(C) For years through 2025, include Include a cost
of equity, which shall be calculated as the sum of the

HB3779 - 344 - LRB104 11172 AAS 21254 b
following:
(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.
At such time as the Board of Governors of the
Federal Reserve System ceases to include the monthly
average yields of 30-year U.S. Treasury bonds in its
weekly H.15 Statistical Release or successor
publication, the monthly average yields of the U.S.
Treasury bonds then having the longest duration
published by the Board of Governors in its weekly H.15
Statistical Release or successor publication shall
instead be used for purposes of this paragraph (2).
For 2026 and subsequent years, include a cost of
equity equal to the value most recently approved by
the Commission for the utility's capital investments
in its distribution system.
(D) Permit and set forth protocols, subject to a
determination of prudence and reasonableness
consistent with Commission practice and law, for the
following:
(i) recovery of incentive compensation expense
that is based on the achievement of operational

HB3779 - 345 - LRB104 11172 AAS 21254 b
metrics, including metrics related to budget
controls, outage duration and frequency, safety,
customer service, efficiency and productivity, and
environmental compliance; however, this protocol
shall not apply if such expense related to costs
incurred under this Section is recovered under
Article IX or Section 16-108.5 of this Act;
incentive compensation expense that is based on
net income or an affiliate's earnings per share
shall not be recoverable under the energy
efficiency formula rate;
(ii) recovery of pension and other
post-employment benefits expense, provided that
such costs are supported by an actuarial study;
however, this protocol shall not apply if such
expense related to costs incurred under this
Section is recovered under Article IX or Section
16-108.5 of this Act;
(iii) recovery of existing regulatory assets
over the periods previously authorized by the
Commission;
(iv) as described in subsection (e),
amortization of costs incurred under this Section;
and
(v) projected, weather normalized billing
determinants for the applicable rate year.

HB3779 - 346 - LRB104 11172 AAS 21254 b
(E) Provide for an annual reconciliation, as
described in paragraph (3) of this subsection (d),
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, 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 energy
efficiency revenue requirement reflected in rates for
each calendar year, beginning with the calendar year
in which the utility files its energy efficiency
formula rate tariff under this paragraph (2), 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 utility shall file, together with its tariff, the
projected costs to be incurred by the utility during the
rate year under the utility's multi-year plan approved
under subsections (f) and (g) of this Section, including,
but not limited to, the projected capital investment costs
and projected regulatory asset balances with
correspondingly updated depreciation and amortization
reserves and expense, that shall populate the energy
efficiency formula rate and set the initial rates under
the formula.
The Commission shall review the proposed tariff in

HB3779 - 347 - LRB104 11172 AAS 21254 b
conjunction with its review of a proposed multi-year plan,
as specified in paragraph (5) of subsection (g) of this
Section. The review shall be based on the same evidentiary
standards, including, but not limited to, those concerning
the prudence and reasonableness of the costs incurred by
the utility, the Commission applies in a hearing to review
a filing for a general increase in rates under Article IX
of this Act. The initial rates shall take effect beginning
with the January monthly billing period following the
Commission's approval.
The tariff's rate design and cost allocation across
customer classes shall be consistent with the utility's
automatic adjustment clause tariff in effect on June 1,
2017 (the effective date of Public Act 99-906); however,
the Commission may revise the tariff's rate design and
cost allocation in subsequent proceedings under paragraph
(3) of this subsection (d).
If the energy efficiency formula rate is terminated,
the then current rates shall remain in effect until such
time as the energy efficiency costs are incorporated into
new rates that are set under this subsection (d) or
Article IX of this Act, subject to retroactive rate
adjustment, with interest, to reconcile rates charged with
actual costs.
(3) The provisions of this paragraph (3) shall only
apply to an electric utility that has elected to file an

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energy efficiency formula rate under paragraph (2) of this
subsection (d). Subsequent to the Commission's issuance of
an order approving the utility's energy efficiency formula
rate structure and protocols, and initial rates under
paragraph (2) of this subsection (d), the utility shall
file, on or before June 1 of each year, with the Chief
Clerk of the Commission its updated cost inputs to the
energy efficiency formula rate for the applicable rate
year and the corresponding new charges, as well as the
information described in paragraph (9) of subsection (g)
of this Section. Each such filing shall conform to the
following requirements and include the following
information:
(A) The inputs to the energy efficiency formula
rate for the applicable rate year shall be based on the
projected costs to be incurred by the utility during
the rate year under the utility's multi-year plan
approved under subsections (f) and (g) of this
Section, including, but not limited to, projected
capital investment costs and projected regulatory
asset balances with correspondingly updated
depreciation and amortization reserves and expense.
The filing shall also include a reconciliation of the
energy efficiency revenue requirement that was in
effect for the prior rate year (as set by the cost
inputs for the prior rate year) with the actual

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revenue requirement for the prior rate year
(determined using a year-end rate base) that uses
amounts reflected in the applicable FERC Form 1 that
reports the actual costs for the prior rate year. Any
over-collection or under-collection indicated by such
reconciliation shall be reflected as a credit against,
or recovered as an additional charge to, respectively,
with interest calculated at a rate equal to the
utility's weighted average cost of capital approved by
the Commission for the prior rate year, the charges
for the applicable rate year. Such over-collection or
under-collection shall be adjusted to remove any
deferred taxes related to the reconciliation, for
purposes of calculating interest at an annual rate of
return equal to the utility's weighted average cost of
capital approved by the Commission for the prior rate
year, 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. Each reconciliation shall be certified by the
participating utility in the same manner that FERC
Form 1 is certified. The filing shall also include the
charge or credit, if any, resulting from the
calculation required by subparagraph (E) of paragraph
(2) of this subsection (d).
Notwithstanding any other provision of law to the

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contrary, the intent of the reconciliation is to
ultimately reconcile both the revenue requirement
reflected in rates for each calendar year, beginning
with the calendar year in which the utility files its
energy efficiency formula rate tariff under paragraph
(2) of this subsection (d), with what the revenue
requirement determined using a year-end rate base for
the applicable calendar year would have been had the
actual cost information for the applicable calendar
year been available at the filing date.
For purposes of this Section, "FERC Form 1" means
the Annual Report of Major Electric Utilities,
Licensees and Others that electric utilities are
required to file with the Federal Energy Regulatory
Commission under the Federal Power Act, Sections 3,
4(a), 304 and 209, modified as necessary to be
consistent with 83 Ill. Adm. Code Part 415 as of May 1,
2011. Nothing in this Section is intended to allow
costs that are not otherwise recoverable to be
recoverable by virtue of inclusion in FERC Form 1.
(B) The new charges shall take effect beginning on
the first billing day of the following January billing
period and remain in effect through the last billing
day of the next December billing period regardless of
whether the Commission enters upon a hearing under
this paragraph (3).

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(C) The filing shall include relevant and
necessary data and documentation for the applicable
rate year. Normalization adjustments shall not be
required.
Within 45 days after the utility files its annual
update of cost inputs to the energy efficiency formula
rate, the Commission shall with reasonable notice,
initiate a proceeding concerning whether the projected
costs to be incurred by the utility and recovered during
the applicable rate year, and that are reflected in the
inputs to the energy efficiency formula rate, are
consistent with the utility's approved multi-year plan
under subsections (f) and (g) of this Section and whether
the costs incurred by the utility during the prior rate
year were prudent and reasonable. The Commission shall
also have the authority to investigate the information and
data described in paragraph (9) of subsection (g) of this
Section, including the proposed adjustment to the
utility's return on equity component of its weighted
average cost of capital. During the course of the
proceeding, each objection shall be stated with
particularity and evidence provided in support thereof,
after which the utility shall have the opportunity to
rebut the evidence. Discovery shall be allowed consistent
with the Commission's Rules of Practice, which Rules of
Practice shall be enforced by the Commission or the

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assigned administrative law judge. The Commission shall
apply the same evidentiary standards, including, but not
limited to, those concerning the prudence and
reasonableness of the costs incurred by the utility,
during the proceeding as it would apply in a proceeding to
review a filing for a general increase in rates under
Article IX of this Act. The Commission shall not, however,
have the authority in a proceeding under this paragraph
(3) to consider or order any changes to the structure or
protocols of the energy efficiency formula rate approved
under paragraph (2) of this subsection (d). In a
proceeding under this paragraph (3), the Commission shall
enter its order no later than the earlier of 195 days after
the utility's filing of its annual update of cost inputs
to the energy efficiency formula rate or December 15. The
utility's proposed return on equity calculation, as
described in paragraphs (7) through (9) of subsection (g)
of this Section, shall be deemed the final, approved
calculation on December 15 of the year in which it is filed
unless the Commission enters an order on or before
December 15, after notice and hearing, that modifies such
calculation consistent with this Section. The Commission's
determinations of the prudence and reasonableness of the
costs incurred, and determination of such return on equity
calculation, for the applicable calendar year shall be
final upon entry of the Commission's order and shall not

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be subject to reopening, reexamination, or collateral
attack in any other Commission proceeding, case, docket,
order, rule, or regulation; however, nothing in this
paragraph (3) shall prohibit a party from petitioning the
Commission to rehear or appeal to the courts the order
under the provisions of this Act.
(e) Beginning on June 1, 2017 (the effective date of
Public Act 99-906), a utility subject to the requirements of
this Section may elect to defer, as a regulatory asset, up to
the full amount of its expenditures incurred under this
Section for each annual period, including, but not limited to,
any expenditures incurred above the funding level set by
subsection (f) of this Section for a given year. The total
expenditures deferred as a regulatory asset in a given year
shall be amortized and recovered over a period that is equal to
the weighted average of the energy efficiency measure lives
implemented for that year that are reflected in the regulatory
asset. 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 balances of all of the
energy efficiency regulatory assets, less any deferred taxes
related to those unamortized balances, 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 through calendar year

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2025 as the sum of the (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; for 2026 and subsequent years the
utility's cost of equity shall be the value most recently
approved by the Commission for the utility's capital
investments in its distribution system. Capital investment
costs shall be depreciated and recovered over their useful
lives consistent with generally accepted accounting
principles. The weighted average cost of capital shall be
applied to the capital investment cost balance, less any
accumulated depreciation and accumulated deferred income
taxes, as of December 31 for a given year.
When an electric utility creates a regulatory asset under
the provisions of this Section, 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 Section
shall recover all of the associated costs as set forth in this
Section. After the Commission has approved the prudence and
reasonableness of the costs that comprise the regulatory

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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.
(f) Beginning in 2017, each electric utility shall file an
energy efficiency plan with the Commission to meet the energy
efficiency standards for the next applicable multi-year period
beginning January 1 of the year following the filing,
according to the schedule set forth in paragraphs (1) through
(3) of this subsection (f). If a utility does not file such a
plan on or before the applicable filing deadline for the plan,
it shall face a penalty of $100,000 per day until the plan is
filed.
(1) No later than 30 days after June 1, 2017 (the
effective date of Public Act 99-906), each electric
utility shall file a 4-year energy efficiency plan
commencing on January 1, 2018 that is designed to achieve
the cumulative persisting annual savings goals specified
in paragraphs (1) through (4) of subsection (b-5) of this
Section or in paragraphs (1) through (4) of subsection
(b-15) of this Section, as applicable, through
implementation of energy efficiency measures; however, the
goals may be reduced if the utility's expenditures are
limited pursuant to subsection (m) of this Section or, for
a utility that serves less than 3,000,000 retail
customers, if each of the following conditions are met:

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(A) the plan's analysis and forecasts of the utility's
ability to acquire energy savings demonstrate that
achievement of such goals is not cost effective; and (B)
the amount of energy savings achieved by the utility as
determined by the independent evaluator for the most
recent year for which savings have been evaluated
preceding the plan filing was less than the average annual
amount of savings required to achieve the goals for the
applicable 4-year plan period. Except as provided in
subsection (m) of this Section, annual increases in
cumulative persisting annual savings goals during the
applicable 4-year plan period shall not be reduced to
amounts that are less than the maximum amount of
cumulative persisting annual savings that is forecast to
be cost-effectively achievable during the 4-year plan
period. The Commission shall review any proposed goal
reduction as part of its review and approval of the
utility's proposed plan.
(2) No later than March 1, 2021, each electric utility
shall file a 4-year energy efficiency plan commencing on
January 1, 2022 that is designed to achieve the cumulative
persisting annual savings goals specified in paragraphs
(5) through (8) of subsection (b-5) of this Section or in
paragraphs (5) through (8) of subsection (b-15) of this
Section, as applicable, through implementation of energy
efficiency measures; however, the goals may be reduced if

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either (1) clear and convincing evidence demonstrates,
through independent analysis, that the expenditure limits
in subsection (m) of this Section preclude full
achievement of the goals or (2) each of the following
conditions are met: (A) the plan's analysis and forecasts
of the utility's ability to acquire energy savings
demonstrate by clear and convincing evidence and through
independent analysis that achievement of such goals is not
cost effective; and (B) the amount of energy savings
achieved by the utility as determined by the independent
evaluator for the most recent year for which savings have
been evaluated preceding the plan filing was less than the
average annual amount of savings required to achieve the
goals for the applicable 4-year plan period. If there is
not clear and convincing evidence that achieving the
savings goals specified in paragraph (b-5) or (b-15) of
this Section is possible both cost-effectively and within
the expenditure limits in subsection (m), such savings
goals shall not be reduced. Except as provided in
subsection (m) of this Section, annual increases in
cumulative persisting annual savings goals during the
applicable 4-year plan period shall not be reduced to
amounts that are less than the maximum amount of
cumulative persisting annual savings that is forecast to
be cost-effectively achievable during the 4-year plan
period. The Commission shall review any proposed goal

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reduction as part of its review and approval of the
utility's proposed plan.
(2.5) The energy efficiency plans of electric
utilities that were approved by the Commission for
calendar years 2022 through 2025, including any stipulated
agreements between the utility and other parties that were
approved by the Commission, shall continue to be in force
through calendar year 2026. The utilities' savings goals
for 2026 shall be the applicable incremental annual
savings goals implicit in the growth in cumulative
persisting annual savings set forth in paragraphs (b-5)
and (b-15) of this Section.
(3) No later than March 1, 2026 2025, each electric
utility shall file a 3-year 4-year energy efficiency plan
commencing on January 1, 2027 2026 that is designed to
achieve lifetime savings equal to the product of the
incremental annual savings goal and the minimum average
savings life defined by subsection (b-16) the cumulative
persisting annual savings goals specified in paragraphs
(9) through (12) of subsection (b-5) of this Section or in
paragraphs (9) through (12) of subsection (b-15) of this
Section, as applicable, through implementation of energy
efficiency measures; however, the goals may be reduced if
either (1) clear and convincing evidence demonstrates,
through independent analysis, that the expenditure limits
in subsection (m) of this Section preclude full

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achievement of the goals or (2) each of the following
conditions are met: (A) the plan's analysis and forecasts
of the utility's ability to acquire energy savings
demonstrate by clear and convincing evidence and through
independent analysis that achievement of such goals is not
cost effective; and (B) the amount of energy savings
achieved by the utility as determined by the independent
evaluator for the most recent year for which savings have
been evaluated preceding the plan filing was less than the
average annual amount of savings required to achieve the
goals for the applicable 4-year plan period. If there is
not clear and convincing evidence that achieving the
savings goals specified in paragraphs (b-5) or (b-15) of
this Section is possible both cost-effectively and within
the expenditure limits in subsection (m), such savings
goals shall not be reduced. Except as provided in
subsection (m) of this Section, annual increases in
cumulative persisting annual savings goals during the
applicable 4-year plan period shall not be reduced to
amounts that are less than the maximum amount of
cumulative persisting annual savings that is forecast to
be cost-effectively achievable during the 4-year plan
period. The Commission shall review any proposed goal
reduction as part of its review and approval of the
utility's proposed plan.
(4) No later than March 1, 2029, and every 4 years

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thereafter, each electric utility shall file a 4-year
energy efficiency plan commencing on January 1, 2030, and
every 4 years thereafter, respectively, that is designed
to achieve lifetime savings equal to the product of the
incremental annual savings goal and the minimum average
savings life described in subsection (b-16) the cumulative
persisting annual savings goals established by the
Illinois Commerce Commission pursuant to direction of
subsections (b-5) and (b-15) of this Section, as
applicable, through implementation of energy efficiency
measures; however, the goals may be reduced if either (1)
clear and convincing evidence and independent analysis
demonstrates that the expenditure limits in subsection (m)
of this Section preclude full achievement of the goals or
(2) each of the following conditions are met: (A) the
plan's analysis and forecasts of the utility's ability to
acquire energy savings demonstrate by clear and convincing
evidence and through independent analysis that achievement
of such goals is not cost-effective; and (B) the amount of
energy savings achieved by the utility as determined by
the independent evaluator for the most recent year for
which savings have been evaluated preceding the plan
filing was less than the average annual amount of savings
required to achieve the goals for the applicable multiyear
4-year plan period. If there is not clear and convincing
evidence that achieving the savings goals specified in

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paragraph (b-16) paragraphs (b-5) or (b-15) of this
Section is possible both cost-effectively and within the
expenditure limits in subsection (m), such savings goals
shall not be reduced. Except as provided in subsection (m)
of this Section, annual increases in cumulative persisting
annual savings goals during the applicable 4-year plan
period shall not be reduced to amounts that are less than
the maximum amount of cumulative persisting annual savings
that is forecast to be cost-effectively achievable during
the 4-year plan period. The Commission shall review any
proposed goal reduction as part of its review and approval
of the utility's proposed plan.
Each utility's plan shall set forth the utility's
proposals to meet the energy efficiency standards identified
in subsection (b-5), or (b-15), or (b-16), as applicable and
as such standards may have been modified under this subsection
(f), taking into account the unique circumstances of the
utility's service territory. For those plans commencing on
January 1, 2018, the Commission shall seek public comment on
the utility's plan and shall issue an order approving or
disapproving each plan no later than 105 days after June 1,
2017 (the effective date of Public Act 99-906). For those
plans commencing after December 31, 2021, the Commission shall
seek public comment on the utility's plan and shall issue an
order approving or disapproving each plan within 6 months
after its submission. If the Commission disapproves a plan,

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the Commission shall, within 30 days, describe in detail the
reasons for the disapproval and describe a path by which the
utility may file a revised draft of the plan to address the
Commission's concerns satisfactorily. If the utility does not
refile with the Commission within 60 days, the utility shall
be subject to penalties at a rate of $100,000 per day until the
plan is filed. This process shall continue, and penalties
shall accrue, until the utility has successfully filed a
portfolio of energy efficiency and demand-response measures.
Penalties shall be deposited into the Energy Efficiency Trust
Fund.
(g) In submitting proposed plans and funding levels under
subsection (f) of this Section to meet the savings goals
identified in subsection (b-5), or (b-15), or (b-16) of this
Section, as applicable, the utility shall:
(1) Demonstrate that its proposed energy efficiency
measures will achieve the applicable requirements that are
identified in subsection (b-5), or (b-15), or (b-16) of
this Section, as modified by subsection (f) of this
Section.
(2) (Blank).
(2.5) Demonstrate consideration of program options for
(A) advancing new building codes, appliance standards, and
municipal regulations governing existing and new building
efficiency improvements and (B) supporting efforts to
improve compliance with new building codes, appliance

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standards and municipal regulations, as potentially
cost-effective means of acquiring energy savings to count
toward savings goals.
(3) Demonstrate that its overall portfolio of
measures, not including low-income programs described in
subsection (c) of this Section, is cost-effective using
the total resource cost test or complies with paragraphs
(1) through (3) of subsection (f) of this Section and
represents a diverse cross-section of opportunities for
customers of all rate classes, other than those customers
described in subsection (l) of this Section, to
participate in the programs. Individual measures need not
be cost effective.
(3.5) Demonstrate that the utility's plan integrates
the delivery of energy efficiency programs with natural
gas efficiency programs, programs promoting distributed
solar, programs promoting demand response and other
efforts to address bill payment issues, including, but not
limited to, LIHEAP and the Percentage of Income Payment
Plan, to the extent such integration is practical and has
the potential to enhance customer engagement, minimize
market confusion, or reduce administrative costs.
(4) Present a third-party energy efficiency
implementation program subject to the following
requirements:
(A) beginning with the year commencing January 1,

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2019, electric utilities that serve more than
3,000,000 retail customers in the State shall fund
third-party energy efficiency programs in an amount
that is no less than $25,000,000 per year, and
electric utilities that serve less than 3,000,000
retail customers but more than 500,000 retail
customers in the State shall fund third-party energy
efficiency programs in an amount that is no less than
$8,350,000 per year;
(B) during 2018, the utility shall conduct a
solicitation process for purposes of requesting
proposals from third-party vendors for those
third-party energy efficiency programs to be offered
during one or more of the years commencing January 1,
2019, January 1, 2020, and January 1, 2021; for those
multi-year plans commencing on January 1, 2022 and
January 1, 2026, the utility shall conduct a
solicitation process during 2021 and 2025,
respectively, for purposes of requesting proposals
from third-party vendors for those third-party energy
efficiency programs to be offered during one or more
years of the respective multi-year plan period; for
each solicitation process, the utility shall identify
the sector, technology, or geographical area for which
it is seeking requests for proposals; the solicitation
process must be either for programs that fill gaps in

HB3779 - 365 - LRB104 11172 AAS 21254 b
the utility's program portfolio and for programs that
target low-income customers, business sectors,
building types, geographies, or other specific parts
of its customer base with initiatives that would be
more effective at reaching these customer segments
than the utilities' programs filed in its energy
efficiency plans;
(C) the utility shall propose the bidder
qualifications, performance measurement process, and
contract structure, which must include a performance
payment mechanism and general terms and conditions;
the proposed qualifications, process, and structure
shall be subject to Commission approval; and
(D) the utility shall retain an independent third
party to score the proposals received through the
solicitation process described in this paragraph (4),
rank them according to their cost per lifetime
kilowatt-hours saved, and assemble the portfolio of
third-party programs.
The electric utility shall recover all costs
associated with Commission-approved, third-party
administered programs regardless of the success of those
programs.
(4.5) Implement cost-effective demand-response
measures to reduce peak demand by 0.1% over the prior year
for eligible retail customers, as defined in Section

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16-111.5 of this Act, and for customers that elect hourly
service from the utility pursuant to Section 16-107 of
this Act, provided those customers have not been declared
competitive. This requirement continues until December 31,
2026.
(5) Include a proposed or revised cost-recovery tariff
mechanism, as provided for under subsection (d) of this
Section, to fund the proposed energy efficiency and
demand-response measures and to ensure the recovery of the
prudently and reasonably incurred costs of
Commission-approved programs.
(6) Provide for an annual independent evaluation of
the performance of the cost-effectiveness of the utility's
portfolio of measures, as well as a full review of the
multi-year plan results of the broader net program impacts
and, to the extent practical, for adjustment of the
measures on a going-forward basis as a result of the
evaluations. The resources dedicated to evaluation shall
not exceed 3% of portfolio resources in any given year.
(7) For electric utilities that serve more than
500,000 3,000,000 retail customers in the State:
(A) Through December 31, 2025, provide for an
adjustment to the return on equity component of the
utility's weighted average cost of capital calculated
under subsection (d) of this Section:
(i) If the independent evaluator determines

HB3779 - 367 - LRB104 11172 AAS 21254 b
that the utility achieved a cumulative persisting
annual savings that is less than the applicable
annual incremental goal, then the return on equity
component shall be reduced by a maximum of 200
basis points in the event that the utility
achieved no more than 75% of such goal. If the
utility achieved more than 75% of the applicable
annual incremental goal but less than 100% of such
goal, then the return on equity component shall be
reduced by 8 basis points for each percent by
which the utility failed to achieve the goal.
(ii) If the independent evaluator determines
that the utility achieved a cumulative persisting
annual savings that is more than the applicable
annual incremental goal, then the return on equity
component shall be increased by a maximum of 200
basis points in the event that the utility
achieved at least 125% of such goal. If the
utility achieved more than 100% of the applicable
annual incremental goal but less than 125% of such
goal, then the return on equity component shall be
increased by 8 basis points for each percent by
which the utility achieved above the goal. If the
applicable annual incremental goal was reduced
under paragraph (1) or (2) of subsection (f) of
this Section, then the following adjustments shall

HB3779 - 368 - LRB104 11172 AAS 21254 b
be made to the calculations described in this item
(ii):
(aa) the calculation for determining
achievement that is at least 125% of the
applicable annual incremental goal shall use
the unreduced applicable annual incremental
goal to set the value; and
(bb) the calculation for determining
achievement that is less than 125% but more
than 100% of the applicable annual incremental
goal shall use the reduced applicable annual
incremental goal to set the value for 100%
achievement of the goal and shall use the
unreduced goal to set the value for 125%
achievement. The 8 basis point value shall
also be modified, as necessary, so that the
200 basis points are evenly apportioned among
each percentage point value between 100% and
125% achievement.
(B) For the period January 1, 2026 through
December 31, 2029 and in all subsequent 4-year
periods, provide for an adjustment to the return on
equity component of the utility's weighted average
cost of capital calculated under subsection (d) of
this Section:
(i) If the product of the incremental annual

HB3779 - 369 - LRB104 11172 AAS 21254 b
savings goal and minimum average savings life
specified in subsection (b-16) of this Section is
unmodified, and if the independent evaluator
determines that the utility achieved lifetime
energy savings that are less than the product of
the incremental annual savings goal and minimum
average savings life specified in subsection
(b-16) of this Section, then the return on equity
component shall be reduced by a maximum of 200
basis points if the utility achieved no more than
66.67% of the lifetime savings goal. If the
utility achieved more than 66.67% but less than
100% of the goal, then the return on equity
component shall be reduced by 6 basis points for
each percent by which the utility failed to
achieve the goal. If the independent evaluator
determines that the utility achieved a cumulative
persisting annual savings that is less than the
applicable annual incremental goal, then the
return on equity component shall be reduced by a
maximum of 200 basis points in the event that the
utility achieved no more than 66% of such goal. If
the utility achieved more than 66% of the
applicable annual incremental goal but less than
100% of such goal, then the return on equity
component shall be reduced by 6 basis points for

HB3779 - 370 - LRB104 11172 AAS 21254 b
each percent by which the utility failed to
achieve the goal.
(ii) If the product of the incremental annual
savings goal and the minimum average savings life
specified in subsection (b-16) of this Section is
unmodified, and if the independent evaluator
determines that the utility achieved lifetime
energy savings that are more than the product of
the incremental annual savings goal and minimum
average savings life specified in subsection
(b-16) of this Section, then the return on equity
component shall be increased by a maximum of 200
basis points if the utility achieved at least
133.33% of such lifetime savings goal. If the
utility achieved more than 100% but less than
133.33% of the goal, then the return on equity
component shall be increased by 6 basis points for
each percent by which the utility exceeded the
goal. If the independent evaluator determines that
the utility achieved a cumulative persisting
annual savings that is more than the applicable
annual incremental goal, then the return on equity
component shall be increased by a maximum of 200
basis points in the event that the utility
achieved at least 134% of such goal. If the
utility achieved more than 100% of the applicable

HB3779 - 371 - LRB104 11172 AAS 21254 b
annual incremental goal but less than 134% of such
goal, then the return on equity component shall be
increased by 6 basis points for each percent by
which the utility achieved above the goal. If the
applicable annual incremental goal was reduced
under paragraph (3) of subsection (f) of this
Section, then the following adjustments shall be
made to the calculations described in this item
(ii):
(iii) If the product of the incremental annual
savings goal and minimum average savings life
specified in subsection (b-16) of this Section is
reduced under paragraph (4) of subsection (f),
then the return on equity shall be reduced by 10
basis points for every percent by which the
utility fails to achieve the modified goal, up to
a maximum of a 200 basis point reduction for
achieving 80% or less of the modified lifetime
savings goal. (aa) the calculation for determining
achievement that is at least 134% of the
applicable annual incremental goal shall use the
unreduced applicable annual incremental goal to
set the value; and
(iv) If the product of the incremental annual
savings goal and minimum average savings life
specified in subsection (b-16) of this Section is

HB3779 - 372 - LRB104 11172 AAS 21254 b
reduced under paragraph (4) of subsection (f), the
return on equity component shall be increased by a
maximum of 200 basis points if the utility
achieved at least 133.33% of the unmodified
lifetime savings goal. If the utility achieved
more than 100% of the modified goal but less than
133.33% of the unmodified goal, then the return on
equity component shall be linearly interpolated
between a 0 basis point increase for meeting 100%
of the modified goal and a 200 basis point
increase for achieving 133.33% of the unmodified
goal. (bb) the calculation for determining
achievement that is less than 134% but more than
100% of the applicable annual incremental goal
shall use the reduced applicable annual
incremental goal to set the value for 100%
achievement of the goal and shall use the
unreduced goal to set the value for 134%
achievement. The 6 basis point value shall also be
modified, as necessary, so that the 200 basis
points are evenly apportioned among each
percentage point value between 100% and 134%
achievement.
(C) Notwithstanding the provisions of
subparagraphs (A) and (B) of this paragraph (7), if
the applicable annual incremental goal for an electric

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utility is ever less than 0.6% of deemed average
weather normalized sales of electric power and energy
during calendar years 2014, 2015, and 2016, an
adjustment to the return on equity component of the
utility's weighted average cost of capital calculated
under subsection (d) of this Section shall be made as
follows:
(i) If the independent evaluator determines
that the utility achieved a cumulative persisting
annual savings that is less than would have been
achieved had the applicable annual incremental
goal been achieved, then the return on equity
component shall be reduced by a maximum of 200
basis points if the utility achieved no more than
75% of its applicable annual total savings
requirement as defined in paragraph (7.5) of this
subsection. If the utility achieved more than 75%
of the applicable annual total savings requirement
but less than 100% of such goal, then the return on
equity component shall be reduced by 8 basis
points for each percent by which the utility
failed to achieve the goal.
(ii) If the independent evaluator determines
that the utility achieved a cumulative persisting
annual savings that is more than would have been
achieved had the applicable annual incremental

HB3779 - 374 - LRB104 11172 AAS 21254 b
goal been achieved, then the return on equity
component shall be increased by a maximum of 200
basis points if the utility achieved at least 125%
of its applicable annual total savings
requirement. If the utility achieved more than
100% of the applicable annual total savings
requirement but less than 125% of such goal, then
the return on equity component shall be increased
by 8 basis points for each percent by which the
utility achieved above the applicable annual total
savings requirement. If the applicable annual
incremental goal was reduced under paragraph (1)
or (2) of subsection (f) of this Section, then the
following adjustments shall be made to the
calculations described in this item (ii):
(aa) the calculation for determining
achievement that is at least 125% of the
applicable annual total savings requirement
shall use the unreduced applicable annual
incremental goal to set the value; and
(bb) the calculation for determining
achievement that is less than 125% but more
than 100% of the applicable annual total
savings requirement shall use the reduced
applicable annual incremental goal to set the
value for 100% achievement of the goal and

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shall use the unreduced goal to set the value
for 125% achievement. The 8 basis point value
shall also be modified, as necessary, so that
the 200 basis points are evenly apportioned
among each percentage point value between 100%
and 125% achievement.
(7.5) For purposes of this Section, the term
"applicable annual incremental goal" means the difference
between the cumulative persisting annual savings goal for
the calendar year that is the subject of the independent
evaluator's determination and the cumulative persisting
annual savings goal for the immediately preceding calendar
year, as such goals are defined in subsections (b-5) and
(b-15) of this Section and as these goals may have been
modified as provided for under subsection (b-20) and
paragraphs (1) and (2) through (3) of subsection (f) of
this Section. Under subsections (b), (b-5), (b-10), and
(b-15) of this Section, a utility must first replace
energy savings from measures that have expired before any
progress towards achievement of its applicable annual
incremental goal may be counted. Savings may expire
because measures installed in previous years have reached
the end of their lives, because measures installed in
previous years are producing lower savings in the current
year than in the previous year, or for other reasons
identified by independent evaluators. Notwithstanding

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anything else set forth in this Section, the difference
between the actual annual incremental savings achieved in
any given year, including the replacement of energy
savings that have expired, and the applicable annual
incremental goal shall not affect adjustments to the
return on equity for subsequent calendar years under this
subsection (g).
In this Section, "applicable annual total savings
requirement" means the total amount of new annual savings
that the utility must achieve in any given year to achieve
the applicable annual incremental goal. This is equal to
the applicable annual incremental goal plus the total new
annual savings that are required to replace savings that
expired in or at the end of the previous year.
(8) For electric utilities that serve less than
3,000,000 retail customers but more than 500,000 retail
customers in the State:
(A) Through December 31, 2026 2025, the applicable
annual incremental goal shall be compared to the
annual incremental savings as determined by the
independent evaluator.
(i) The return on equity component shall be
reduced by 8 basis points for each percent by
which the utility did not achieve 84.4% of the
applicable annual incremental goal.
(ii) The return on equity component shall be

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increased by 8 basis points for each percent by
which the utility exceeded 100% of the applicable
annual incremental goal.
(iii) The return on equity component shall not
be increased or decreased if the annual
incremental savings as determined by the
independent evaluator is greater than 84.4% of the
applicable annual incremental goal and less than
100% of the applicable annual incremental goal.
(iv) The return on equity component shall not
be increased or decreased by an amount greater
than 200 basis points pursuant to this
subparagraph (A).
(B) For the period of January 1, 2027 2026 through
December 31, 2029 , provide for an adjustment to the
return on equity component of the utility's weighted
average cost of capital calculated under subsection
(d) of this Section: and in all subsequent 4-year
periods, the applicable annual incremental goal shall
be compared to the annual incremental savings as
determined by the independent evaluator.
(i) The return on equity component shall be
reduced by 6 basis points for each percent by
which the utility did not achieve 85% 100% of the
lifetime savings that is the product of the
incremental annual savings goal and the minimum

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average savings life specified in subsection
(b-16) of this Section, up to a maximum reduction
of 200 basis points for achieving 51.67% or less
of the lifetime savings goal applicable annual
incremental goal.
(ii) The return on equity component shall be
increased by 6 basis points for each percent by
which the utility exceeded 100% of the lifetime
savings that is the product of the incremental
annual savings goal and the minimum average
savings life specified in subsection (b-16) of
this Section, up to a maximum increase of 200
basis points for achieving 133.33% or more of the
lifetime savings goal applicable annual
incremental goal.
(iii) The return on equity component shall not
be increased or decreased by an amount greater
than 200 basis points pursuant to this
subparagraph (B).
(C) For the period of January 1, 2030 through
December 31, 2033, provide for an adjustment to the
return on equity component of the utility's weighted
average cost of capital calculated under subsection
(d) of this Section:
(i) If the product of the incremental annual
savings goal and minimum average savings life

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specified in subsection (b-16) of this Section is
unmodified, and if the independent evaluator
determines that the utility achieved lifetime
energy savings that are less than 95% of the
product of the incremental annual savings goal and
minimum average savings life specified in
subsection (b-16) of this Section, the return on
equity component shall be reduced by 3 basis
points for each percent by which the utility did
not achieve 95% of the lifetime savings goal, plus
an additional 3 basis point reduction for each
percent by which the utility did not achieve 90%
of the lifetime savings goal, up to a maximum
reduction of 200 basis points for achieving 59.17%
or less of the lifetime savings goal.
(ii) If the product of the incremental annual
savings goal and minimum average savings life
specified in subsection (b-16) of this Section is
unmodified, and if the independent evaluator
determines that the utility achieved lifetime
energy savings that are greater than the product
of the incremental annual savings goal and minimum
average savings life specified in subsection
(b-16) of this Section, the return on equity
component shall be increased by 6 basis points for
each percent by which the utility exceeded 100% of

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the lifetime savings goal, up to a maximum
increase of 200 basis points for achieving 133.33%
or more of the lifetime savings goal.
(iii) If the product of the incremental annual
savings goal and minimum average savings life
specified in subsection (b-16) of this Section is
reduced under paragraph (4) of subsection (f), the
return on equity component shall be reduced by 10
basis points for every percent by which the
utility fails to achieve the modified lifetime
savings goal, up to a maximum of a 200 basis point
reduction for achieving 80% or less of the
modified goal.
(iv) If the product of the incremental annual
savings goal and minimum average savings life
specified in subsection (b-16) of this Section is
reduced under paragraph (4) of subsection (f), the
return on equity component shall be increased by a
maximum of 200 basis points if the utility
achieved at least 133.33% of the unmodified
lifetime savings goal. If the utility achieved
more than 100% of the modified goal but less than
133.33% of the unmodified goal, then the return on
equity component shall be linearly interpolated
between a 0 basis point increase for meeting 100%
of the modified goal and a 200 basis point

HB3779 - 381 - LRB104 11172 AAS 21254 b
increase for achieving 133.33% of the unmodified
goal.
(D) For the period of January 1, 2034 through
December 31, 2037, as well as for all subsequent
four-year plan periods, provide for an adjustment to
the return on equity component of the utility's
weighted average cost of capital calculated under
subsection (d) of this Section:
(i) If the product of the incremental annual
savings goal and minimum average savings life
specified in subsection (b-16) of this Section is
unmodified, and if the independent evaluator
determines that the utility achieved lifetime
energy savings that is less than 100% of the
product of the incremental annual savings goal and
minimum average savings life specified in
subsection (b-16) of this Section, the return on
equity component shall be reduced by 6 basis
points for each percent by which the utility did
not achieve 100% of the lifetime savings goal, up
to a maximum reduction of 200 basis points for
achieving 66.67% or less of the lifetime savings
goal.
(ii) If the product of the incremental annual
savings goal and minimum average savings life
specified in subsection (b-16) of this Section is

HB3779 - 382 - LRB104 11172 AAS 21254 b
unmodified, and if the independent evaluator
determines that the utility achieved lifetime
energy savings that is greater than the product of
the incremental annual savings goal and minimum
average savings life specified in subsection
(b-16) of this Section, the return on equity
component shall be increased by 6 basis points for
each percent by which the utility exceeded 100% of
the lifetime savings goal, up to a maximum
increase of 200 basis points for achieving 133.33%
or more of the lifetime savings goal.
(iii) If the product of the incremental annual
savings goal and minimum average savings life
specified in subsection (b-16) of this Section is
reduced under paragraph (4) of subsection (f),
then the return on equity shall be reduced by 10
basis points for every percent by which the
utility fails to achieve the modified lifetime
savings goal, up to a maximum of a 200 basis point
reduction for achieving 80% or less of the
modified goal.
(iv) If the product of the incremental annual
savings goal and minimum average savings life
specified in subsection (b-16) of this Section is
reduced under paragraph (4) of subsection (f), the
return on equity component shall be increased by a

HB3779 - 383 - LRB104 11172 AAS 21254 b
maximum of 200 basis points if the utility
achieved at least 133.33% of the unmodified
lifetime savings goal. If the utility achieved
more than 100% of the modified goal but less than
133.33% of the unmodified goal, then the return on
equity component shall be linearly interpolated
between a 0 basis point increase for meeting 100%
of the modified goal and a 200 basis point
increase for achieving 133.33% of the unmodified
goal.
(C) Notwithstanding provisions in subparagraphs
(A) and (B) of paragraph (7) of this subsection, if the
applicable annual incremental goal for an electric
utility is ever less than 0.6% of deemed average
weather normalized sales of electric power and energy
during calendar years 2014, 2015 and 2016, an
adjustment to the return on equity component of the
utility's weighted average cost of capital calculated
under subsection (d) of this Section shall be made as
follows:
(i) The return on equity component shall be
reduced by 8 basis points for each percent by
which the utility did not achieve 100% of the
applicable annual total savings requirement.
(ii) The return on equity component shall be
increased by 8 basis points for each percent by

HB3779 - 384 - LRB104 11172 AAS 21254 b
which the utility exceeded 100% of the applicable
annual total savings requirement.
(iii) The return on equity component shall not
be increased or decreased by an amount greater
than 200 basis points pursuant to this
subparagraph (C).
(D) If the applicable annual incremental goal was
reduced under paragraph (1), (2), (3), or (4) of
subsection (f) of this Section, then the following
adjustments shall be made to the calculations
described in subparagraphs (A), (B), and (C) of this
paragraph (8):
(i) The calculation for determining
achievement that is at least 125% or 134%, as
applicable, of the applicable annual incremental
goal or the applicable annual total savings
requirement, as applicable, shall use the
unreduced applicable annual incremental goal to
set the value.
(ii) For the period through December 31, 2025,
the calculation for determining achievement that
is less than 125% but more than 100% of the
applicable annual incremental goal or the
applicable annual total savings requirement, as
applicable, shall use the reduced applicable
annual incremental goal to set the value for 100%

HB3779 - 385 - LRB104 11172 AAS 21254 b
achievement of the goal and shall use the
unreduced goal to set the value for 125%
achievement. The 8 basis point value shall also be
modified, as necessary, so that the 200 basis
points are evenly apportioned among each
percentage point value between 100% and 125%
achievement.
(iii) For the period of January 1, 2026
through December 31, 2029 and all subsequent
4-year periods, the calculation for determining
achievement that is less than 125% or 134%, as
applicable, but more than 100% of the applicable
annual incremental goal or the applicable annual
total savings requirement, as applicable, shall
use the reduced applicable annual incremental goal
to set the value for 100% achievement of the goal
and shall use the unreduced goal to set the value
for 125% achievement. The 6 basis-point value or 8
basis-point value, as applicable, shall also be
modified, as necessary, so that the 200 basis
points are evenly apportioned among each
percentage point value between 100% and 125% or
between 100% and 134% achievement, as applicable.
(9) The utility shall submit the energy savings data
to the independent evaluator no later than 30 days after
the close of the plan year. The independent evaluator

HB3779 - 386 - LRB104 11172 AAS 21254 b
shall determine the cumulative persisting annual savings
and annual incremental savings for a given plan year, as
well as an estimate of job impacts and other macroeconomic
impacts of the efficiency programs for that year, no later
than 120 days after the close of the plan year. The utility
shall submit an informational filing to the Commission no
later than 160 days after the close of the plan year that
attaches the independent evaluator's final report
identifying the cumulative persisting annual savings for
the year and calculates, under paragraph (7) or (8) of
this subsection (g), as applicable, any resulting change
to the utility's return on equity component of the
weighted average cost of capital applicable to the next
plan year beginning with the January monthly billing
period and extending through the December monthly billing
period. However, if the utility recovers the costs
incurred under this Section under paragraphs (2) and (3)
of subsection (d) of this Section, then the utility shall
not be required to submit such informational filing, and
shall instead submit the information that would otherwise
be included in the informational filing as part of its
filing under paragraph (3) of such subsection (d) that is
due on or before June 1 of each year.
For those utilities that must submit the informational
filing, the Commission may, on its own motion or by
petition, initiate an investigation of such filing,

HB3779 - 387 - LRB104 11172 AAS 21254 b
provided, however, that the utility's proposed return on
equity calculation shall be deemed the final, approved
calculation on December 15 of the year in which it is filed
unless the Commission enters an order on or before
December 15, after notice and hearing, that modifies such
calculation consistent with this Section.
The adjustments to the return on equity component
described in paragraph paragraphs (7) and (8) of this
subsection (g) shall be applied as described in such
paragraphs through a separate tariff mechanism, which
shall be filed by the utility under subsections (f) and
(g) of this Section.
(9.5) The utility must demonstrate how it will ensure
that program implementation contractors and energy
efficiency installation vendors will promote workforce
equity and quality jobs.
(9.6) Utilities shall collect data necessary to ensure
compliance with paragraph (9.5) no less than quarterly and
shall communicate progress toward compliance with
paragraph (9.5) to program implementation contractors and
energy efficiency installation vendors no less than
quarterly. Utilities shall work with relevant vendors,
providing education, training, and other resources needed
to ensure compliance and, where necessary, adjusting or
terminating work with vendors that cannot assist with
compliance.

HB3779 - 388 - LRB104 11172 AAS 21254 b
(10) Utilities required to implement efficiency
programs under subsections (b-5), and (b-10), and (b-16)
shall report annually to the Illinois Commerce Commission
and the General Assembly on how hiring, contracting, job
training, and other practices related to its energy
efficiency programs enhance the diversity of vendors
working on such programs. These reports must include data
on vendor and employee diversity, including data on the
implementation of paragraphs (9.5) and (9.6). If the
utility is not meeting the requirements of paragraphs
(9.5) and (9.6), the utility shall submit a plan to adjust
their activities so that they meet the requirements of
paragraphs (9.5) and (9.6) within the following year.
(h) No more than 4% of energy efficiency and
demand-response program revenue may be allocated for research,
development, or pilot deployment of new equipment or measures.
Electric utilities shall work with interested stakeholders to
formulate a plan for how these funds should be spent,
incorporate statewide approaches for these allocations, and
file a 4-year plan that demonstrates that collaboration. If a
utility files a request for modified annual energy savings
goals with the Commission, then a utility shall forgo spending
portfolio dollars on research and development proposals.
(i) When practicable, electric utilities shall incorporate
advanced metering infrastructure data into the planning,
implementation, and evaluation of energy efficiency measures

HB3779 - 389 - LRB104 11172 AAS 21254 b
and programs, subject to the data privacy and confidentiality
protections of applicable law.
(j) The independent evaluator shall follow the guidelines
and use the savings set forth in Commission-approved energy
efficiency policy manuals and technical reference manuals, as
each may be updated from time to time. Until such time as
measure life values for energy efficiency measures implemented
for low-income households under subsection (c) of this Section
are incorporated into such Commission-approved manuals, the
low-income measures shall have the same measure life values
that are established for same measures implemented in
households that are not low-income households.
(k) Notwithstanding any provision of law to the contrary,
an electric utility subject to the requirements of this
Section may file a tariff cancelling an automatic adjustment
clause tariff in effect under this Section or Section 8-103,
which shall take effect no later than one business day after
the date such tariff is filed. Thereafter, the utility shall
be authorized to defer and recover its expenditures incurred
under this Section through a new tariff authorized under
subsection (d) of this Section or in the utility's next rate
case under Article IX or Section 16-108.5 of this Act, with
interest at an annual rate equal to the utility's weighted
average cost of capital as approved by the Commission in such
case. If the utility elects to file a new tariff under
subsection (d) of this Section, the utility may file the

HB3779 - 390 - LRB104 11172 AAS 21254 b
tariff within 10 days after June 1, 2017 (the effective date of
Public Act 99-906), and the cost inputs to such tariff shall be
based on the projected costs to be incurred by the utility
during the calendar year in which the new tariff is filed and
that were not recovered under the tariff that was cancelled as
provided for in this subsection. Such costs shall include
those incurred or to be incurred by the utility under its
multi-year plan approved under subsections (f) and (g) of this
Section, including, but not limited to, projected capital
investment costs and projected regulatory asset balances with
correspondingly updated depreciation and amortization reserves
and expense. The Commission shall, after notice and hearing,
approve, or approve with modification, such tariff and cost
inputs no later than 75 days after the utility filed the
tariff, provided that such approval, or approval with
modification, shall be consistent with the provisions of this
Section to the extent they do not conflict with this
subsection (k). The tariff approved by the Commission shall
take effect no later than 5 days after the Commission enters
its order approving the tariff.
No later than 60 days after the effective date of the
tariff cancelling the utility's automatic adjustment clause
tariff, the utility shall file a reconciliation that
reconciles the moneys collected under its automatic adjustment
clause tariff with the costs incurred during the period
beginning June 1, 2016 and ending on the date that the electric

HB3779 - 391 - LRB104 11172 AAS 21254 b
utility's automatic adjustment clause tariff was cancelled. In
the event the reconciliation reflects an under-collection, the
utility shall recover the costs as specified in this
subsection (k). If the reconciliation reflects an
over-collection, the utility shall apply the amount of such
over-collection as a one-time credit to retail customers'
bills.
(l) (Blank). For the calendar years covered by a
multi-year plan commencing after December 31, 2017,
subsections (a) through (j) of this Section do not apply to
eligible large private energy customers that have chosen to
opt out of multi-year plans consistent with this subsection
(1).
(1) For purposes of this subsection (l), "eligible
large private energy customer" means any retail customers,
except for federal, State, municipal, and other public
customers, of an electric utility that serves more than
3,000,000 retail customers, except for federal, State,
municipal and other public 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.
For purposes of this subsection (l), "retail customer" has
the meaning set forth in Section 16-102 of this Act.

HB3779 - 392 - LRB104 11172 AAS 21254 b
However, for a business entity with multiple sites located
in the State, where at least one of those sites qualifies
as an eligible large private energy customer, then any of
that business entity's sites, properly identified on a
form for notice, shall be considered eligible large
private energy customers for the purposes of this
subsection (l). A determination of whether this subsection
is applicable to a customer shall be made for each
multi-year plan beginning after December 31, 2017. The
criteria for determining whether this subsection (l) is
applicable to a retail customer shall be based on the 12
consecutive billing periods prior to the start of the
first year of each such multi-year plan.
(2) Within 45 days after September 15, 2021 (the
effective date of Public Act 102-662), the Commission
shall prescribe the form for notice required for opting
out of energy efficiency programs. The notice must be
submitted to the retail electric utility 12 months before
the next energy efficiency planning cycle. However, within
120 days after the Commission's initial issuance of the
form for notice, eligible large private energy customers
may submit a form for notice to an electric utility. The
form for notice for opting out of energy efficiency
programs shall include all of the following:
(A) a statement indicating that the customer has
elected to opt out;

HB3779 - 393 - LRB104 11172 AAS 21254 b
(B) the account numbers for the customer accounts
to which the opt out shall apply;
(C) the mailing address associated with the
customer accounts identified under subparagraph (B);
(D) an American Society of Heating, Refrigerating,
and Air-Conditioning Engineers (ASHRAE) level 2 or
higher audit report conducted by an independent
third-party expert identifying cost-effective energy
efficiency project opportunities that could be
invested in over the next 10 years. A retail customer
with specialized processes may utilize a self-audit
process in lieu of the ASHRAE audit;
(E) a description of the customer's plans to
reallocate the funds toward internal energy efficiency
efforts identified in the subparagraph (D) report,
including, but not limited to: (i) strategic energy
management or other programs, including descriptions
of targeted buildings, equipment and operations; (ii)
eligible energy efficiency measures; and (iii)
expected energy savings, itemized by technology. If
the subparagraph (D) audit report identifies that the
customer currently utilizes the best available energy
efficient technology, equipment, programs, and
operations, the customer may provide a statement that
more efficient technology, equipment, programs, and
operations are not reasonably available as a means of

HB3779 - 394 - LRB104 11172 AAS 21254 b
satisfying this subparagraph (E); and
(F) the effective date of the opt out, which will
be the next January 1 following notice of the opt out.
(3) Upon receipt of a properly and timely noticed
request for opt out submitted by an eligible large private
energy customer, the retail electric utility shall grant
the request, file the request with the Commission and,
beginning January 1 of the following year, the opted out
customer shall no longer be assessed the costs of the plan
and shall be prohibited from participating in that 4-year
plan cycle to give the retail utility the certainty to
design program plan proposals.
(4) Upon a customer's election to opt out under
paragraphs (1) and (2) of this subsection (l) and
commencing on the effective date of said opt out, the
account properly identified in the customer's notice under
paragraph (2) shall not be subject to any cost recovery
and shall not be eligible to participate in, or directly
benefit from, compliance with energy efficiency cumulative
persisting savings requirements under subsections (a)
through (j).
(5) A utility's cumulative persisting annual savings
targets will exclude any opted out load.
(6) The request to opt out is only valid for the
requested plan cycle. An eligible large private energy
customer must also request to opt out for future energy

HB3779 - 395 - LRB104 11172 AAS 21254 b
plan cycles, otherwise the customer will be included in
the future energy plan cycle.
(m) Notwithstanding the requirements of this Section, as
part of a proceeding to approve a multi-year plan under
subsections (f) and (g) of this Section if the multi-year plan
has been designed to maximize savings, but does not meet the
cost cap limitations of this Section, the Commission shall
reduce the amount of energy efficiency measures implemented
for any single year, and whose costs are recovered under
subsection (d) of this Section, by an amount necessary to
limit the estimated average net increase due to the cost of the
measures to no more than
(1) 3.5% for each of the 4 years beginning January 1,
2018,
(2) (blank),
(3) 4% for each of the 4 years beginning January 1,
2022,
(3.5) 4.25% for 2026;
(4) 4.25% for electric utilities that serve more than
3,000,000 retail customers in the State, and 5.19% for
electric utilities with less than 3,000,000 retail
customers but more than 500,000 retail customers in the
state, for the 3 4 years beginning January 1, 2027 2026,
and
(5) the percentage specified in paragraph (4) 4.25%
plus an increase sufficient to account for the rate of

HB3779 - 396 - LRB104 11172 AAS 21254 b
inflation between January 1, 2027 2026 and January 1 of
the first year of each subsequent 4-year plan cycle,
of the average amount paid per kilowatthour by residential
eligible retail customers during calendar year 2015 for plans
in effect through 2026 and calendar year 2023 for plans
commencing in 2027 and beyond. An electric utility may plan to
spend up to 10% more in any year during an applicable
multi-year plan period to cost-effectively achieve additional
savings so long as the average over the applicable multi-year
plan period does not exceed the percentages defined in items
(1) through (5). To determine the total amount that may be
spent by an electric utility in any single year, the
applicable percentage of the average amount paid per
kilowatthour shall be multiplied by the total amount of energy
delivered by such electric utility in the calendar year 2015
for plans in effect through 2026 and calendar year 2023 for
plans commencing in 2027 and beyond, adjusted to reflect the
proportion of the utility's load attributable to customers
that have opted out of subsections (a) through (j) of this
Section under subsection (l) of this Section. For purposes of
this subsection (m), the amount paid per kilowatthour
includes, without limitation, estimated amounts paid for
supply, transmission, distribution, surcharges, and add-on
taxes. For purposes of this Section, "eligible retail
customers" shall have the meaning set forth in Section
16-111.5 of this Act. Once the Commission has approved a plan

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under subsections (f) and (g) of this Section, no subsequent
rate impact determinations shall be made.
(n) A utility shall take advantage of the efficiencies
available through existing Illinois Home Weatherization
Assistance Program infrastructure and services, such as
enrollment, marketing, quality assurance and implementation,
which can reduce the need for similar services at a lower cost
than utility-only programs, subject to capacity constraints at
community action agencies, for both single-family and
multifamily weatherization services, to the extent Illinois
Home Weatherization Assistance Program community action
agencies provide multifamily services. A utility's plan shall
demonstrate that in formulating annual weatherization budgets,
it has sought input and coordination with community action
agencies regarding agencies' capacity to expand and maximize
Illinois Home Weatherization Assistance Program delivery using
the ratepayer dollars collected under this Section.
(Source: P.A. 102-662, eff. 9-15-21; 103-154, eff. 6-30-23.)
(220 ILCS 5/8-104B new)
Sec. 8-104B. Gas energy efficiency.
(a) As used in this Section:
"Benefit-cost ratio" means the ratio of the net present
value of the total benefits of the measures to the net present
value of the total costs as calculated over the lifetime of the
measures.

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"Cost-effective measure" means a measure that satisfies
the total resource cost test.
"Energy efficiency measure" means a measure that reduces
(i) the total Btus of electricity and natural gas and other
utility-delivered gaseous fuels needed to meet an end use or
end uses and (ii) the amount of natural gas and other
utility-delivered gaseous fuels consumed on site, at the home
or business facility, to meet an end use or end uses.
"Total resource cost test" has the same meaning as set
forth in Section 1-10 of the Illinois Power Agency Act.
(b) It is the policy of the State for gas utilities to be
required to use cost-effective energy efficiency measures to
reduce delivery load. Requiring investment in cost-effective
energy efficiency measures will reduce direct and indirect
costs to consumers by decreasing environmental impacts,
reducing the amount of natural gas and other utility-delivered
gaseous fuels that need to be purchased, and avoiding or
delaying the need for new transmission, distribution, storage,
and other related infrastructure. Moreover, the public
interest is served by allowing gas utilities to recover costs
for reasonably and prudently incurred expenditures for energy
efficiency measures.
(c) This Section applies to all gas distribution utilities
in the State and supersedes Section 8-104 beginning January 1,
2027.
(d) Natural gas utilities shall implement cost-effective

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energy efficiency measures to achieve all of the following
requirements:
(1) Total incremental annual savings shall be equal to
at least 0.6% of annual sales to distribution customers in
2027, 0.8% of such sales in 2028 and at least 1% of such
sales in 2029 and each subsequent year. For the purposes
of this Section, "incremental annual savings" means the
total gas savings from all measures installed in a
calendar year that will be realized within 12 months of
each measure's installation. For the purpose of
calculating savings as a percent of sales to distribution
customers for a given program year, the denominator of
sales to distribution customers shall be annual average
sales over the second, third, and fourth full calendar
years prior to the beginning of the program year.
(2) The savings achieved must have an average life of
at least 12 years. In no event can more than one-fifth of
the incremental annual savings counted towards a utility's
annual savings goal in any given year be derived from
efficiency measures with average savings lives of less
than 5 years. Average savings life is defined as the
lifetime savings that would be realized as a result of a
utility's efficiency programs divided by the incremental
annual savings such programs produce. Average savings
lives may be shorter than the average operational lives of
measures installed if the measures do not produce savings

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in every year in which they operate or if the savings that
measures produce decline during their operational lives.
(3) Except as provided in subsection (A) of this
Section, savings may not be applied toward achievement of
utility savings goals if the savings arise from the
installation of efficient new gas furnaces, gas boilers,
gas water heaters, or other gas-consuming equipment in a
residential building, such as a single-family,
individually-metered multifamily, or master-metered
multifamily building.
(A) Savings may be applied toward achievement of
utility savings goals if the savings arise from the
installation of gas furnaces through income-eligible
programs when it is determined the existing furnace is
no longer working, requires significant annual
maintenance costs in order to remain operational, or
is creating a health and safety hazard.
(4) At least 67% of the entire budget for efficiency
programs shall be spent on energy efficiency measures that
reduce space heating needs through improvements to the
efficiency of building envelopes, including, but not
limited to, insulation measures and efficient windows and
energy efficiency measures that reduce air leakage through
improvements to systems for distributing heat, including,
but not limited to, duct leakage reduction, duct
insulation, or pipe insulation in buildings or through

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improved heating systems controls, including, but not
limited to, advanced thermostats and demand control
ventilation. Spending on efficient furnaces, efficient
boilers, or other efficient heating systems is permitted
within business efficiency programs but does not count
toward this minimum requirement for spending on building
envelope, heating distribution, and control efficiencies.
Spending on income-qualified building envelope measures,
heating distribution system measures, and heating controls
does count toward this requirement. The portion of portfolio
spending on program marketing, training of installers, audits
of buildings, inspections of work performed, and other
administrative and technical expenses that are clearly tied to
promotion or installation of building envelope or heating
distribution system measures shall count toward this
requirement. If this minimum requirement is not met, any
performance incentive earned under subsection (h) should be
reduced by the percentage point level of shortfall in meeting
this requirement.
(5) The portion of the entire budget for efficiency
programs that is spent on efficiency measures for
income-qualified households shall be the greater of 25% or
5 percentage points more than the proportion of total
residential and business customer gas sales going to
income-qualified households. For purposes of this Section,
households at or below 80% of area median income are

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income-qualified. At least 80% of spending on measures in
programs targeted at income-qualified households shall be
delivered through whole building weatherization programs
and spent on measures that reduce space heating needs
through improvements to the building envelope, heating
distribution systems, or heating controls. The utilities
shall invest in health and safety measures appropriate and
necessary for comprehensively weatherizing the homes and
multifamily buildings of income-qualified households, with
up to 15% of income-qualified program spending made
available for such purposes. The ratio of spending on
efficiency programs targeted at multifamily buildings of
income-qualified households to spending on energy
efficiency programs targeted at single-family buildings of
income-qualified households shall be designed to achieve
levels of savings from each building type that are
approximately proportional to the magnitude of
cost-effective lifetime savings potential in each building
type. The gas utilities shall participate in a Low-Income
Energy Efficiency Accountability Committee as established
in Section 8-103B.
Gas utilities must conduct customer outreach and education
efforts in equity investment eligible communities in order to
provide notice of and explanations concerning the following
types of programs:
(A) energy efficiency programs, the Illinois Solar

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for All Program, and whole home retrofit programs that
reduce natural gas usage;
(B) income-qualified financial assistance
programs, including rebate programs from the federal
government; and
(C) general education programs designed to explain
utility bills and the decisions customers can make to
lower energy usage.
These outreach and education efforts must be brought to
communities in a diversity of ways, must be created with input
from members of the communities, and must be provided through,
among other things:
(i) information on customers' bills in the
main languages spoken in the communities;
(ii) a quarterly posting in local newspapers
that cover the service area;
(iii) a dedicated section on the
investor-owned utility's website; and
(iv) in-person and virtual educational
sessions that take place in the income-qualified
and Justice40 community, provide food and child
care for participating customers, and are
codesigned with interested community-based
organization representatives.
(6) Implementation of energy efficiency measures and
programs targeted at income-qualified households shall be

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contracted, when practicable, to independent third parties
that have demonstrated the capability of serving those
households, with a preference for not-for-profit entities
and government agencies that have existing relationships
with, experience serving, or working directly within and
alongside income-qualified communities in the State. Each
gas utility shall develop and implement reporting
procedures that address and assist in determining the
amount of energy savings that can be applied to the
income-qualified procurement and expenditure requirements
set forth in this paragraph.
(7) A minimum of 10% of the utility's entire portfolio
funding level for a given year shall be used to procure
cost-effective energy efficiency measures from units of
local government, municipal corporations, school
districts, public housing, community college districts,
and nonprofit-owned buildings as long as a minimum
percentage of available funds shall be used to procure
energy efficiency from public housing, which percentage
shall be, at a minimum, equal to public housing's share of
public building energy consumption. Spending on public
housing may count toward minimum spending requirements on
efficiency improvements for income-qualified households.
(e) Notwithstanding any other provision of law, a utility
providing approved energy efficiency measures in the State may
recover all reasonable and prudently incurred costs of those

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measures from its retail customers. However, nothing in this
subsection permits the double recovery of such costs from
customers.
(f) Beginning in 2026, each gas utility shall file an
energy efficiency plan with the Commission to meet the energy
efficiency standards in subsection (d) for the next applicable
multiyear period beginning January 1 of the year following the
filing, according to the schedule set forth in paragraphs (1)
through (4). If a utility does not file such a plan on or
before the applicable filing deadline for the plan, the
utility shall be liable for a civil penalty of $100,000 per day
until the plan is filed.
(1) The energy efficiency plans of gas utilities that
were approved by the Commission for calendar years 2022
through 2025, including any stipulated agreements between
the utility and other parties that were approved by the
Commission, shall continue to be in force through calendar
year 2026. The utilities' savings goals for 2026 shall be
equal to the average annual savings goal approved for the
years 2022 through 2025.
(2) No later than March 1, 2026, each gas utility
shall file a 3-year energy efficiency plan that takes
effect on January 1, 2027 and is designed to achieve,
through implementation of emergency efficiency measures,
the incremental annual savings goals, minimum average
savings life, and other requirements specified in

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paragraphs (1) through (7) of subsection (d). An energy
efficiency plan submitted by a gas utility under this
paragraph supersedes any energy efficiency plan previous
approved by the Commission for calendar year 2027 or
thereafter.
(3) Beginning in 2029 and every 4 years thereafter,
each gas utility shall file by no later than March 1 of the
applicable year, a 4-year energy efficiency plan that
takes effect on the following January 1 and is designed to
achieve, through implementation of energy efficiency
measures, the incremental annual savings goals, minimum
average savings life, and other requirements specified in
paragraphs (1) through (7) of subsection (d). However, the
incremental annual savings goals may be reduced if the
plan's analysis and forecasts of the utility's ability to
acquire energy savings demonstrate by clear and convincing
evidence and through independent analysis that achievement
of such goals is not cost-effective. In no event may
incremental annual savings goals for any year be reduced
to levels below (i) those actually achieved in the
calendar year before the plan filing, (ii) those forecast
to be achieved in the calendar year in which the plan
filing is made, or (iii) 0.75% of sales. The Commission
shall review any proposed goal reduction as part of its
review and approval of the utility's proposed plan.
(4) Each utility's plan shall set forth the utility's

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proposals to meet the energy efficiency standards
identified in subsection (d). The Commission shall seek
public comment on each plan that takes effect on or after
January 1, 2027 and shall issue an order approving or
disapproving the plan within 6 months after its
submission. If the Commission disapproves a plan, the
Commission shall, within 30 days, describe in detail the
reasons for the disapproval and describe a path by which
the utility may file a revised draft of the plan to address
the Commission's concerns satisfactorily. If the utility
does not refile with the Commission within 60 days, the
utility shall be subject to civil penalties at a rate of
$100,000 per day until the plan is refiled. This process
shall continue, and penalties shall accrue, until the
utility has successfully filed a portfolio of energy
efficiency measures. Penalties shall be deposited into the
Energy Efficiency Trust Fund.
(g) In submitting proposed plans and funding levels under
subsection (f) to meet the savings goals identified in
subsection (d), the utility shall:
(1) demonstrate that its proposed energy efficiency
measures will achieve the requirements that are identified
in subsection (d);
(2) demonstrate consideration of program options for
supporting efforts to improve compliance with new building
codes, appliance standards, and municipal regulations as

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potentially cost-effective means of acquiring energy
savings to count toward energy savings goals;
(3) demonstrate that its overall portfolio of measures
and programs, not including income-qualified programs
described in subsection (d), is cost-effective using the
total resource cost test and represents a diverse cross
section of opportunities for customers of all rate classes
to participate in programs. Individual measures need not
be cost-effective;
(4) demonstrate that the utility's plan integrates the
delivery of energy efficiency programs with electric
efficiency programs, programs promoting demand response,
and other efforts to address bill payment issues,
including, but not limited to, the Low Income Home Energy
Assistance Program and the Percentage of Income Payment
Plans;
(5) include a proposed or revised cost-recovery
mechanism to fund the proposed energy efficiency measures
and ensure the recovery of the prudently and reasonably
incurred costs of Commission-approved programs;
(6) provide, using not more than 3% of portfolio
resources in any given year, an annual independent
evaluation of the performance and cost-effectiveness of
the utility's portfolio of measures and programs;
(7) demonstrate how it will ensure that program
implementation contractors and energy efficiency

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installation vendors will promote workforce equity and
quality jobs. Utilities shall collect, and make publicly
available at least quarterly, data necessary to
demonstrate how efforts are advancing workforce equity.
Utilities shall work with relevant vendors providing
education, training, and other resources needed to ensure
compliance and, where necessary, adjusting or terminating
work with vendors that cannot assist with compliance; and
(8) include any plans for research, development, or
pilot deployment of new measures or program approaches.
For utilities with unmodified savings goals, no more than
4% of energy efficiency portfolio spending may be
allocated for such purposes. For utilities with modified
savings goals, no more than 2% of energy efficiency
portfolio spending may be allocated for such purposes.
Utilities shall work with interested stakeholders to
formulate a plan for how any proposed funds should be
spent, incorporate statewide approaches for these
allocations whenever such approaches would be more
effective or cost-efficient, and demonstrate such
collaboration in the utilities' plans.
(h) Each gas utility shall be eligible to earn a
shareholder incentive for effective implementation of its
efficiency programs. The incentive shall be tied to each
utility's annual energy efficiency spending and its savings.
There shall be no incentive if the independent evaluator

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determines the utility either (i) did not fully meet all of the
requirements specified in paragraphs (3) through (7) of
subsection (d) or (ii) failed to achieve at least 90% of its
lifetime savings goal. If a utility meets all of the
requirements specified in paragraphs (3) through (7) of
subsection (d), it can earn an incentive equal to 0.4% of total
annual efficiency spending in the year being evaluated for
every one percentage point above 90% of its lifetime savings
goal that it achieves for that year, with a maximum incentive
of 12% for achieving 120% of its lifetime savings goal. For
purposes of this section, a utility's lifetime savings goal is
the product of its incremental savings goal specified in
paragraph (1) of subsection (d) and the minimum average
savings life specified in paragraph (2) of subsection (d).
(i) The utility shall submit energy savings data to the
independent evaluator no later than 30 days after the close of
the plan year. The independent evaluator shall determine the
incremental annual savings and average savings life, as well
as an estimate of the job impacts and other macroeconomic
impacts of the efficiency programs for that year, achieved no
later than 120 days after the close of the plan year. The
utility shall submit an informational filing to the Commission
no later than 160 days after the close of the plan year that
attaches the independent evaluator's final report identifying
the incremental annual savings for the year, identifying
average savings life for the year, documenting compliance with

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other requirements in subsection (d), and, as applicable, the
magnitude of any shareholder incentive which the utility has
earned.
(j) Gas utilities shall report annually to the Commission
and General Assembly on how hiring, contracting, job training,
and other practices related to its energy efficiency programs
enhance the diversity of vendors working on such programs.
These reports must include data on vendor and employee
diversity.
(k) The independent evaluator shall follow the guidelines
and use the savings set forth in Commission-approved energy
efficiency policy manuals and technical reference manuals, as
each may be updated from time to time. Until measure life
values for energy efficiency measures implemented for
income-qualified households are separately incorporated into
such Commission-approved manuals, the income-qualified
measures shall have the same measure life values that are
established for the same measures implemented in households
that are not income-qualified households.
(220 ILCS 5/8-406) (from Ch. 111 2/3, par. 8-406)
Sec. 8-406. Certificate of public convenience and
necessity.
(a) No public utility not owning any city or village
franchise nor engaged in performing any public service or in
furnishing any product or commodity within this State as of

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July 1, 1921 and not possessing a certificate of public
convenience and necessity from the Illinois Commerce
Commission, the State Public Utilities Commission, or the
Public Utilities Commission, at the time Public Act 84-617
goes into effect (January 1, 1986), shall transact any
business in this State until it shall have obtained a
certificate from the Commission that public convenience and
necessity require the transaction of such business. A
certificate of public convenience and necessity requiring the
transaction of public utility business in any area of this
State shall include authorization to the public utility
receiving the certificate of public convenience and necessity
to construct such plant, equipment, property, or facility as
is provided for under the terms and conditions of its tariff
and as is necessary to provide utility service and carry out
the transaction of public utility business by the public
utility in the designated area.
(b) No public utility shall begin the construction of any
new plant, equipment, property, or facility which is not in
substitution of any existing plant, equipment, property, or
facility, or any extension or alteration thereof or in
addition thereto, unless and until it shall have obtained from
the Commission a certificate that public convenience and
necessity require such construction. Whenever after a hearing
the Commission determines that any new construction or the
transaction of any business by a public utility will promote

HB3779 - 413 - LRB104 11172 AAS 21254 b
the public convenience and is necessary thereto, it shall have
the power to issue certificates of public convenience and
necessity. The Commission shall determine that proposed
construction will promote the public convenience and necessity
only if the utility demonstrates: (1) that the proposed
construction is necessary to provide adequate, reliable, and
efficient service to its customers and is the least-cost means
of satisfying the service needs of its customers or that the
proposed construction will promote the development of an
effectively competitive electricity market that operates
efficiently, is equitable to all customers, and is the least
cost means of satisfying those objectives; (2) that the
utility is capable of efficiently managing and supervising the
construction process and has taken sufficient action to ensure
adequate and efficient construction and supervision thereof;
and (3) that the utility is capable of financing the proposed
construction without significant adverse financial
consequences for the utility or its customers; and (4) that
the public utility plans to implement grid enhancing
technologies maximizing the value of the project, such as but
not limited to advanced power flow control, topology
optimization, and dynamic line rating, unless the public
utility demonstrates grid enhancing technologies are not cost
effective.
(b-5) As used in this subsection (b-5):
"Qualifying direct current applicant" means an entity that

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seeks to provide direct current bulk transmission service for
the purpose of transporting electric energy in interstate
commerce.
"Qualifying direct current project" means a high voltage
direct current electric service line that crosses at least one
Illinois border, the Illinois portion of which is physically
located within the region of the Midcontinent Independent
System Operator, Inc., or its successor organization, and runs
through the counties of Pike, Scott, Greene, Macoupin,
Montgomery, Christian, Shelby, Cumberland, and Clark, is
capable of transmitting electricity at voltages of 345
kilovolts or above, and may also include associated
interconnected alternating current interconnection facilities
in this State that are part of the proposed project and
reasonably necessary to connect the project with other
portions of the grid.
Notwithstanding any other provision of this Act, a
qualifying direct current applicant that does not own,
control, operate, or manage, within this State, any plant,
equipment, or property used or to be used for the transmission
of electricity at the time of its application or of the
Commission's order may file an application on or before
December 31, 2023 with the Commission pursuant to this Section
or Section 8-406.1 for, and the Commission may grant, a
certificate of public convenience and necessity to construct,
operate, and maintain a qualifying direct current project. The

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qualifying direct current applicant may also include in the
application requests for authority under Section 8-503. The
Commission shall grant the application for a certificate of
public convenience and necessity and requests for authority
under Section 8-503 if it finds that the qualifying direct
current applicant and the proposed qualifying direct current
project satisfy the requirements of this subsection and
otherwise satisfy the criteria of this Section or Section
8-406.1 and the criteria of Section 8-503, as applicable to
the application and to the extent such criteria are not
superseded by the provisions of this subsection. The
Commission's order on the application for the certificate of
public convenience and necessity shall also include the
Commission's findings and determinations on the request or
requests for authority pursuant to Section 8-503. Prior to
filing its application under either this Section or Section
8-406.1, the qualifying direct current applicant shall conduct
3 public meetings in accordance with subsection (h) of this
Section. If the qualifying direct current applicant
demonstrates in its application that the proposed qualifying
direct current project is designed to deliver electricity to a
point or points on the electric transmission grid in either or
both the PJM Interconnection, LLC or the Midcontinent
Independent System Operator, Inc., or their respective
successor organizations, the proposed qualifying direct
current project shall be deemed to be, and the Commission

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shall find it to be, for public use. If the qualifying direct
current applicant further demonstrates in its application that
the proposed transmission project has a capacity of 1,000
megawatts or larger and a voltage level of 345 kilovolts or
greater, the proposed transmission project shall be deemed to
satisfy, and the Commission shall find that it satisfies, the
criteria stated in item (1) of subsection (b) of this Section
or in paragraph (1) of subsection (f) of Section 8-406.1, as
applicable to the application, without the taking of
additional evidence on these criteria. Prior to the transfer
of functional control of any transmission assets to a regional
transmission organization, a qualifying direct current
applicant shall request Commission approval to join a regional
transmission organization in an application filed pursuant to
this subsection (b-5) or separately pursuant to Section 7-102
of this Act. The Commission may grant permission to a
qualifying direct current applicant to join a regional
transmission organization if it finds that the membership, and
associated transfer of functional control of transmission
assets, benefits Illinois customers in light of the attendant
costs and is otherwise in the public interest. Nothing in this
subsection (b-5) requires a qualifying direct current
applicant to join a regional transmission organization.
Nothing in this subsection (b-5) requires the owner or
operator of a high voltage direct current transmission line
that is not a qualifying direct current project to obtain a

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certificate of public convenience and necessity to the extent
it is not otherwise required by this Section 8-406 or any other
provision of this Act.
(c) As used in this subsection (c):
"Decommissioning" has the meaning given to that term in
subsection (a) of Section 8-508.1.
"Nuclear power reactor" has the meaning given to that term
in Section 8 of the Nuclear Safety Law of 2004.
After the effective date of this amendatory Act of the
103rd General Assembly, no construction shall commence on any
new nuclear power reactor with a nameplate capacity of more
than 300 megawatts of electricity to be located within this
State, and no certificate of public convenience and necessity
or other authorization shall be issued therefor by the
Commission, until the Illinois Emergency Management Agency and
Office of Homeland Security, in consultation with the Illinois
Environmental Protection Agency and the Illinois Department of
Natural Resources, finds that the United States Government,
through its authorized agency, has identified and approved a
demonstrable technology or means for the disposal of high
level nuclear waste, or until such construction has been
specifically approved by a statute enacted by the General
Assembly. Beginning January 1, 2026, construction may commence
on a new nuclear power reactor with a nameplate capacity of 300
megawatts of electricity or less within this State if the
entity constructing the new nuclear power reactor has obtained

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all permits, licenses, permissions, or approvals governing the
construction, operation, and funding of decommissioning of
such nuclear power reactors required by: (1) this Act; (2) any
rules adopted by the Illinois Emergency Management Agency and
Office of Homeland Security under the authority of this Act;
(3) any applicable federal statutes, including, but not
limited to, the Atomic Energy Act of 1954, the Energy
Reorganization Act of 1974, the Low-Level Radioactive Waste
Policy Amendments Act of 1985, and the Energy Policy Act of
1992; (4) any regulations promulgated or enforced by the U.S.
Nuclear Regulatory Commission, including, but not limited to,
those codified at Title X, Parts 20, 30, 40, 50, 70, and 72 of
the Code of Federal Regulations, as from time to time amended;
and (5) any other federal or State statute, rule, or
regulation governing the permitting, licensing, operation, or
decommissioning of such nuclear power reactors. None of the
rules developed by the Illinois Emergency Management Agency
and Office of Homeland Security or any other State agency,
board, or commission pursuant to this Act shall be construed
to supersede the authority of the U.S. Nuclear Regulatory
Commission. The changes made by this amendatory Act of the
103rd General Assembly shall not apply to the uprate, renewal,
or subsequent renewal of any license for an existing nuclear
power reactor that began operation prior to the effective date
of this amendatory Act of the 103rd General Assembly.
None of the changes made in this amendatory Act of the

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103rd General Assembly are intended to authorize the
construction of nuclear power plants powered by nuclear power
reactors that are not either: (1) small modular nuclear
reactors; or (2) nuclear power reactors licensed by the U.S.
Nuclear Regulatory Commission to operate in this State prior
to the effective date of this amendatory Act of the 103rd
General Assembly.
(d) In making its determination under subsection (b) of
this Section, the Commission shall attach primary weight to
the cost or cost savings to the customers of the utility. The
Commission may consider any or all factors which will or may
affect such cost or cost savings, including the public
utility's engineering judgment regarding the materials used
for construction.
(e) The Commission may issue a temporary certificate which
shall remain in force not to exceed one year in cases of
emergency, to assure maintenance of adequate service or to
serve particular customers, without notice or hearing, pending
the determination of an application for a certificate, and may
by regulation exempt from the requirements of this Section
temporary acts or operations for which the issuance of a
certificate will not be required in the public interest.
A public utility shall not be required to obtain but may
apply for and obtain a certificate of public convenience and
necessity pursuant to this Section with respect to any matter
as to which it has received the authorization or order of the

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Commission under the Electric Supplier Act, and any such
authorization or order granted a public utility by the
Commission under that Act shall as between public utilities be
deemed to be, and shall have except as provided in that Act the
same force and effect as, a certificate of public convenience
and necessity issued pursuant to this Section.
No electric cooperative shall be made or shall become a
party to or shall be entitled to be heard or to otherwise
appear or participate in any proceeding initiated under this
Section for authorization of power plant construction and as
to matters as to which a remedy is available under the Electric
Supplier Act.
(f) Such certificates may be altered or modified by the
Commission, upon its own motion or upon application by the
person or corporation affected. Unless exercised within a
period of 2 years from the grant thereof, authority conferred
by a certificate of convenience and necessity issued by the
Commission shall be null and void.
No certificate of public convenience and necessity shall
be construed as granting a monopoly or an exclusive privilege,
immunity or franchise.
(g) A public utility that undertakes any of the actions
described in items (1) through (3) of this subsection (g) or
that has obtained approval pursuant to Section 8-406.1 of this
Act shall not be required to comply with the requirements of
this Section to the extent such requirements otherwise would

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apply. For purposes of this Section and Section 8-406.1 of
this Act, "high voltage electric service line" means an
electric line having a design voltage of 100,000 or more. For
purposes of this subsection (g), a public utility may do any of
the following:
(1) replace or upgrade any existing high voltage
electric service line and related facilities,
notwithstanding its length;
(2) relocate any existing high voltage electric
service line and related facilities, notwithstanding its
length, to accommodate construction or expansion of a
roadway or other transportation infrastructure; or
(3) construct a high voltage electric service line and
related facilities that is constructed solely to serve a
single customer's premises or to provide a generator
interconnection to the public utility's transmission
system and that will pass under or over the premises owned
by the customer or generator to be served or under or over
premises for which the customer or generator has secured
the necessary right of way.
(h) A public utility seeking to construct a high-voltage
electric service line and related facilities (Project) must
show that the utility has held a minimum of 2 pre-filing public
meetings to receive public comment concerning the Project in
each county where the Project is to be located, no earlier than
6 months prior to filing an application for a certificate of

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public convenience and necessity from the Commission. Notice
of the public meeting shall be published in a newspaper of
general circulation within the affected county once a week for
3 consecutive weeks, beginning no earlier than one month prior
to the first public meeting. If the Project traverses 2
contiguous counties and where in one county the transmission
line mileage and number of landowners over whose property the
proposed route traverses is one-fifth or less of the
transmission line mileage and number of such landowners of the
other county, then the utility may combine the 2 pre-filing
meetings in the county with the greater transmission line
mileage and affected landowners. All other requirements
regarding pre-filing meetings shall apply in both counties.
Notice of the public meeting, including a description of the
Project, must be provided in writing to the clerk of each
county where the Project is to be located. A representative of
the Commission shall be invited to each pre-filing public
meeting.
(i) For applications filed after August 18, 2015 (the
effective date of Public Act 99-399), the Commission shall, by
certified mail, notify each owner of record of land, as
identified in the records of the relevant county tax assessor,
included in the right-of-way over which the utility seeks in
its application to construct a high-voltage electric line of
the time and place scheduled for the initial hearing on the
public utility's application. The utility shall reimburse the

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Commission for the cost of the postage and supplies incurred
for mailing the notice.
(Source: P.A. 102-609, eff. 8-27-21; 102-662, eff. 9-15-21;
102-813, eff. 5-13-22; 102-931, eff. 5-27-22; 103-569, eff.
6-1-24.)
(220 ILCS 5/8-406.1)
Sec. 8-406.1. Certificate of public convenience and
necessity; expedited procedure.
(a) A public utility may apply for a certificate of public
convenience and necessity pursuant to this Section for the
construction of any new high voltage electric service line and
related facilities (Project). To facilitate the expedited
review process of an application filed pursuant to this
Section, an application shall include all of the following:
(1) Information in support of the application that
shall include the following:
(A) A detailed description of the Project,
including location maps and plot plans to scale
showing all major components.
(B) The following engineering data:
(i) a detailed Project description including:
(I) name and destination of the Project;
(II) design voltage rating (kV);
(III) operating voltage rating (kV); and
(IV) normal peak operating current rating;

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(ii) a conductor, structures, and substations
description including:
(I) conductor size and type;
(II) type of structures;
(III) height of typical structures;
(IV) an explanation why these structures
were selected;
(V) dimensional drawings of the typical
structures to be used in the Project; and
(VI) a list of the names of all new (and
existing if applicable) substations or
switching stations that will be associated
with the proposed new high voltage electric
service line;
(iii) the location of the site and
right-of-way including:
(I) miles of right-of-way;
(II) miles of circuit;
(III) width of the right-of-way; and
(IV) a brief description of the area
traversed by the proposed high voltage
electric service line, including a description
of the general land uses in the area and the
type of terrain crossed by the proposed line;
(iv) assumptions, bases, formulae, and methods
used in the development and preparation of the

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diagrams and accompanying data, and a technical
description providing the following information:
(I) number of circuits, with
identification as to whether the circuit is
overhead or underground;
(II) the operating voltage and frequency;
and
(III) conductor size and type and number
of conductors per phase;
(v) if the proposed interconnection is an
overhead line, the following additional
information also must be provided:
(I) the wind and ice loading design
parameters;
(II) a full description and drawing of a
typical supporting structure, including
strength specifications;
(III) structure spacing with typical
ruling and maximum spans;
(IV) conductor (phase) spacing; and
(V) the designed line-to-ground and
conductor-side clearances;
(vi) if an underground or underwater
interconnection is proposed, the following
additional information also must be provided:
(I) burial depth;

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(II) type of cable and a description of
any required supporting equipment, such as
insulation medium pressurizing or forced
cooling;
(III) cathodic protection scheme; and
(IV) type of dielectric fluid and
safeguards used to limit potential spills in
waterways;
(vii) technical diagrams that provide
clarification of any item under this item (1)
should be included; and
(viii) applicant shall provide and identify a
primary right-of-way and one or more alternate
rights-of-way for the Project as part of the
filing. To the extent applicable, for each
right-of-way, an applicant shall provide the
information described in this subsection (a). Upon
a showing of good cause in its filing, an
applicant may be excused from providing and
identifying alternate rights-of-way.
(2) An application fee of $100,000, which shall be
paid into the Public Utility Fund at the time the Chief
Clerk of the Commission deems it complete and accepts the
filing.
(3) Information showing that the utility has held a
minimum of 3 pre-filing public meetings to receive public

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comment concerning the Project in each county where the
Project is to be located, no earlier than 6 months prior to
the filing of the application. Notice of the public
meeting shall be published in a newspaper of general
circulation within the affected county once a week for 3
consecutive weeks, beginning no earlier than one month
prior to the first public meeting. If the Project
traverses 2 contiguous counties and where in one county
the transmission line mileage and number of landowners
over whose property the proposed route traverses is 1/5 or
less of the transmission line mileage and number of such
landowners of the other county, then the utility may
combine the 3 pre-filing meetings in the county with the
greater transmission line mileage and affected landowners.
All other requirements regarding pre-filing meetings shall
apply in both counties. Notice of the public meeting,
including a description of the Project, must be provided
in writing to the clerk of each county where the Project is
to be located. A representative of the Commission shall be
invited to each pre-filing public meeting.
For applications filed after the effective date of this
amendatory Act of the 99th General Assembly, the Commission
shall, by certified mail, notify each owner of record of the
land, as identified in the records of the relevant county tax
assessor, included in the primary or alternate rights-of-way
identified in the utility's application of the time and place

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scheduled for the initial hearing upon the public utility's
application. The utility shall reimburse the Commission for
the cost of the postage and supplies incurred for mailing the
notice.
(b) At the first status hearing the administrative law
judge shall set a schedule for discovery that shall take into
consideration the expedited nature of the proceeding.
(c) Nothing in this Section prohibits a utility from
requesting, or the Commission from approving, protection of
confidential or proprietary information under applicable law.
The public utility may seek confidential protection of any of
the information provided pursuant to this Section, subject to
Commission approval.
(d) The public utility shall publish notice of its
application in the official State newspaper within 10 days
following the date of the application's filing.
(e) The public utility shall establish a dedicated website
for the Project 3 weeks prior to the first public meeting and
maintain the website until construction of the Project is
complete. The website address shall be included in all public
notices.
(f) The Commission shall, after notice and hearing, grant
a certificate of public convenience and necessity filed in
accordance with the requirements of this Section if, based
upon the application filed with the Commission and the
evidentiary record, it finds the Project will promote the

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public convenience and necessity and that all of the following
criteria are satisfied:
(1) That the Project is necessary to provide adequate,
reliable, and efficient service to the public utility's
customers and is the least-cost means of satisfying the
service needs of the public utility's customers or that
the Project will promote the development of an effectively
competitive electricity market that operates efficiently,
is equitable to all customers, and is the least cost means
of satisfying those objectives.
(2) That the public utility is capable of efficiently
managing and supervising the construction process and has
taken sufficient action to ensure adequate and efficient
construction and supervision of the construction.
(3) That the public utility is capable of financing
the proposed construction without significant adverse
financial consequences for the utility or its customers.
(4) That the public utility plans to implement grid
enhancing technologies maximizing the value of the
project, such as but not limited to advanced power flow
control, topology optimization, and dynamic line rating,
unless the public utility demonstrates grid enhancing
technologies are not cost effective.
(g) The Commission shall issue its decision with findings
of fact and conclusions of law granting or denying the
application no later than 150 days after the application is

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filed. The Commission may extend the 150-day deadline upon
notice by an additional 75 days if, on or before the 30th day
after the filing of the application, the Commission finds that
good cause exists to extend the 150-day period.
(h) In the event the Commission grants a public utility's
application for a certificate pursuant to this Section, the
public utility shall pay a one-time construction fee to each
county in which the Project is constructed within 30 days
after the completion of construction. The construction fee
shall be $20,000 per mile of high voltage electric service
line constructed in that county, or a proportionate fraction
of that fee. The fee shall be in lieu of any permitting fees
that otherwise would be imposed by a county. Counties
receiving a payment under this subsection (h) may distribute
all or portions of the fee to local taxing districts in that
county.
(i) Notwithstanding any other provisions of this Act, a
decision granting a certificate under this Section shall
include an order pursuant to Section 8-503 of this Act
authorizing or directing the construction of the high voltage
electric service line and related facilities as approved by
the Commission, in the manner and within the time specified in
said order.
(Source: P.A. 102-931, eff. 5-27-22.)
(220 ILCS 5/8-512)

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Sec. 8-512. Renewable energy access plan.
(a) It is the policy of this State to promote
cost-effective transmission system development that ensures
reliability of the electric transmission system, lowers carbon
emissions, minimizes long-term costs for consumers, and
supports the electric policy goals of this State. The General
Assembly finds that:
(1) Transmission planning, primarily for reliability
purposes, but also for economic and public policy reasons
is conducted by regional transmission organizations in
which transmission-owning Illinois utilities and other
stakeholders are members.
(2) Order No. 1000 of the Federal Energy Regulatory
Commission requires regional transmission organizations to
plan for transmission system needs in light of State
public policies and to accept input from states during the
transmission system planning processes.
(3) The State of Illinois does not currently have a
comprehensive power and environmental policy planning
process to identify transmission infrastructure needs that
can serve as a vital input into the regional and
interregional transmission organization planning
processes conducted under Order No. 1000 and other laws
and regulations.
(4) This State is an electricity generation and power
transmission hub, and can leverage that position to invest

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in infrastructure that enables new and existing Illinois
generators to meet the public policy goals of the State of
Illinois and of interconnected states while
cost-effectively supporting tens of thousands of jobs in
the renewable energy sector in this State.
(5) The nation has a need to readily access this
State's low-cost, clean electric power, and this State
also desires access to clean energy resources in other
states to develop and support its low-carbon economy and
keep electricity prices low in Illinois and interconnected
States.
(6) Existing transmission infrastructure may constrain
the State's achievement of 100% renewable energy by 2050,
the accelerated adoption of electric vehicles in a just
and equitable way, and electrification of additional
sectors of the Illinois economy.
(7) Transmission system congestion within this State
and the regional transmission organizations serving this
State limits the ability of this State's existing and new
electric generation facilities that do not emit carbon
dioxide, including renewable energy resources and zero
emission facilities, to serve the public policy goals of
this State and other states, which constrains investment
in this State.
(8) Investment in infrastructure to support existing
and new electric generation facilities that do not emit

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carbon dioxide, including renewable energy resources and
zero emission facilities, stimulates significant economic
development and job growth in this State, as well as
creates environmental and public health benefits in this
State.
(9) Creating a forward-looking plan for this State's
electric transmission infrastructure, as opposed to
relying on case-by-case development and repeated marginal
upgrades, will achieve a lower-cost system for Illinois'
electricity customers. A forward-looking plan can also
help integrate and achieve a comprehensive set of
objectives and multiple state, regional, and national
policy goals.
(10) Alternatives to overhead electric transmission
lines can achieve cost-effective resolution of system
impacts and warrant investigation of the circumstances
under which those alternatives should be considered and
approved. The alternatives are likely to be beneficial as
investment in electric transmission infrastructure moves
forward.
(11) Because transmission planning is conducted
primarily by the regional transmission organizations, the
Commission should be advocating for the State's interests
at the regional transmission organizations to ensure that
such planning facilitates the State's policies and goals,
including overall consumer savings, power system

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reliability, economic development, environmental
improvement, and carbon reduction.
(b) Consistent with the findings identified in subsection
(a), the Commission shall open an investigation to develop and
adopt a renewable energy access plan no later than December
31, 2022. To assist and support the Commission in the
development of the plan, the Commission shall retain the
services of technical and policy experts with relevant fields
of expertise, solicit technical and policy analysis from the
public, and provide for a 120-day open public comment period
after publication of a draft report, which shall be published
no later than 90 days after the comment period ends. The plan
shall, at a minimum, do the following:
(1) designate renewable energy access plan zones
throughout this State in areas in which renewable energy
resources and suitable land areas are sufficient for
developing generating capacity from renewable energy
technologies;
(2) develop a plan to achieve transmission capacity
necessary to deliver the electric output from renewable
energy technologies in the renewable energy access plan
zones to customers in Illinois and other states in a
manner that is most beneficial and cost-effective to
customers;
(3) use this State's position as an electricity
generation and power transmission hub to create new

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

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(7) present the Commission's conclusions and proposed
recommendations based on its analysis and use the findings
and policy recommendations to determine actions that the
Commission should take.
(c) No later than December 31, 2025, and every other year
thereafter, the Commission shall open an investigation to
develop and adopt an updated renewable energy access plan
that, at a minimum, evaluates the implementation and
effectiveness of the renewable energy access plan, recommends
improvements to the renewable energy access plan, and provides
changes to transmission capacity necessary to deliver electric
output from the renewable energy access plan zones.
(d) Advanced Transmission Technologies Study.
(1) The General Assembly finds that advanced
transmission technologies have an important role to play
in meeting the State's achievement of 100% renewable
energy by 2050.
(2) "Advanced Transmission Technology" includes but
not limited to: (i) technology that dynamically adjusts
the rated capacity of transmission lines based on
real-time conditions; (ii) advanced power flow controls
used to actively control the flow of electricity across
transmission lines to optimize usage and/or relieve
congestion; (iii) software or hardware used to identify
optimal transmission grid configurations and/or enable
routing power flows around congestion points; (iv)

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advanced transmission line conductors that have a direct
current electrical resistance at least 10 percent lower
than existing conductors of a similar diameter on the
system.
(3) No later than January 1, 2026, and once every two
years thereafter, each transmission-owning Illinois
utility shall prepare an analysis to identify
opportunities where Advanced Transmission Technology
deployments on an element of the utility's existing
transmission system could achieve any of the following
purposes: (A) enhance system resilience or reliability;
(B) reduce potential siting conflicts or land impacts from
the development of new transmission lines; (C) promote the
cost-effective delivery of power from renewable energy
resources interconnected to the bulk electric system to
meet the renewable portfolio standard targets under
subsection (c) of Section 1-75 of the Illinois Power
Agency Act; (D) enable the interconnection of renewable
energy resources to meet the renewable portfolio standard
targets under subsection (c) of Section 1-75 of the
Illinois Power Agency Act; or (E) reduce curtailment of
renewable and/or zero-carbon resources. The Advanced
Transmission Technology Deployment Study should at a
minimum evaluate the four types of Advanced Transmission
Technologies defined in this subsection (d) and shall
provide a timeline for deploying any Advanced Transmission

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Technology found to achieve the purposes of this
subsection.
(4) Within 30 days of completing the Advanced
Transmission Technology Deployment Study, the
transmission-owning Illinois utilities shall submit the
study to the Commission. The Commission shall open a
Notice of Inquiry or other public, non-decisional
proceeding to provide opportunity for public comment on
the Advanced Transmission Technology Deployment Study. The
transmission-owning Illinois utilities shall submit the
final Advanced Transmission Technology Deployment Study to
the relevant regional transmission planning entities for
consideration in upcoming regional planning studies.
(e) Grid Capacity Optimization Plan.
(1) The General Assembly finds that achieving
Illinois' climate goals and preserving affordability
requires optimizing the use of the existing transmission
system. With generator retirements and anticipated
increases in large point load growth on the horizon,
Illinois must fully leverage the existing capacity of the
transmission system to address near-term system needs.
Furthermore, many existing resources do not fully utilize
the total grid capacity allocated to them, creating
opportunities for new resources to connect to the grid
without the need for new grid upgrades, and take advantage
of this unused capacity provided they do not exceed the

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limits assigned to the existing resource.
(2) No later than January 1, 2026, the Commission
shall draft a Grid Capacity Optimization Plan. Upon
completion of the Grid Capacity Optimization Plan, the
Commission shall open a Notice of Inquiry or other public,
non-decisional proceeding to provide opportunity for
public comment. Within 90 days of the conclusion of the
public comment period, the Commission shall post the final
Grid Capacity Optimization Plan on its website. The Grid
Capacity Optimization Plan shall achieve the following:
(A) Identify existing or new state processes that
could make full use of the headroom that exists on the
Illinois system and any reforms necessary to utilize
the identified capacity, including but not limited to
mechanisms to incentivize investment of new supply at
locations that optimizes the existing transmission
system, and distribution system planning and expansion
that would enable greater access of distributed energy
resources to wholesale markets;
(B) Identify interconnection reforms at the
Midcontinent Independent System Operator, Inc., PJM
Interconnection, LLC, or their successor constructs to
access existing headroom and deploy renewable
resources and/or storage resources on the Illinois
transmission system; and
(C) Identify deficiencies in planning processes at

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the Midcontinent Independent System Operator, Inc.,
PJM Interconnection, LLC, or their successor
constructs that may introduce delay or unnecessary
costs in responding to plant closures.
(f) Transmission Headroom Study.
(1) No later than January 1, 2026, and updated every
other year thereafter, the Commission shall conduct a
comprehensive Transmission Headroom Study that shall, at a
minimum, identify the points of interconnection with
unused, existing transmission headroom on the Illinois
system, including that available capacity behind existing,
underutilized points of interconnection. "Headroom"
includes but is not limited to: (i) underutilized
transmission capacity; (ii) utilization of Surplus
Interconnection Service as defined in FERC Order 845, and
subsequent decisions; (iii) transmission capacity that is
unavailable due to deficiencies in regional transmission
organization procedures; and (iv) transmission capacity
expected to become available due to reasonably anticipated
generator retirements. The Commission shall coordinate
with the Midcontinent Independent System Operator, Inc.
and PJM Interconnection, LLC or their successor constructs
to access any data necessary to complete the Transmission
Headroom Study, and upon request, additional data shall be
provided to the Commission by the relevant Illinois
transmission owners. Additionally, the Illinois Power

HB3779 - 441 - LRB104 11172 AAS 21254 b
Agency's Office of Energy Modeling shall provide any
technical support the Commission requires to conduct the
Transmission Headroom Study, including but not limited to
performing the headroom analysis or recommending external
consultants or other external entities if necessary.
(2) Within 30 days of completing the Transmission
Headroom Study, the Commission shall open a Notice of
Inquiry or other public, non-decisional proceeding to
provide opportunity for public comment. The Commission
shall submit the final Transmission Headroom Study to the
Midcontinent Independent System Operator, Inc. and PJM
Interconnection, LLC or their successor constructs for
consideration in upcoming regional planning studies,
interconnection reform efforts, and resource adequacy
evaluations.
(A) As part of updating the Transmission Headroom
Study, the Commission shall evaluate the effectiveness
of enacted state processes and regional transmission
organization interconnection and planning processes in
unlocking the available headroom identified in the
most recent Transmission Headroom Study and
recommending any new or modified policies to better
utilize the identified headroom.
(B) As part of updating the Transmission Headroom
Study, the Commission shall evaluate how deficiencies
in the retirement or replacement planning procedures

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at the Midcontinent Independent System Operator, Inc.
and PJM Interconnection, LLC, or their successor
constructs may have contributed to any extended
operations of electric generating units as described
in subsection (k-5)(1) of Section 9.15 of the
Environmental Protection Act, and quantify the
associated excess costs borne by Illinois consumers as
a result.
(g) The Commission shall advocate at relevant regional
transmission organizations and through their relevant state
engagement forums to recommend new regional transmission
organization policies, rules, or actions necessary to achieve
the interconnection planning and generator replacement reforms
identified in the Grid Capacity Optimization Plan described in
subsection (e) or as updated in the most recent Transmission
Headroom Study described in subsection (f). If necessary, the
Commission shall coordinate with other state entities,
including the Office of the Illinois Attorney General, on
appropriate legal action to remedy any aspect of a regional
transmission organization's practices that fails to meet the
needs of Illinois consumers and the requirements of Illinois
law.
(Source: P.A. 102-662, eff. 9-15-21; 103-380, eff. 1-1-24.)
(220 ILCS 5/9-229)
Sec. 9-229. Consideration of attorney and expert

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compensation as an expense and intervenor compensation fund.
(a) The Commission shall specifically assess the justness
and reasonableness of any amount expended by a public utility
to compensate attorneys or technical experts to prepare and
litigate a general rate case filing. This issue shall be
expressly addressed in the Commission's final order.
(b) The State of Illinois shall create a Consumer
Intervenor Compensation Fund subject to the following:
(1) Provision of compensation for Consumer Interest
Representatives that intervene in Illinois Commerce
Commission proceedings will increase public engagement,
encourage additional transparency, expand the information
available to the Commission, and improve decision-making.
(2) As used in this Section, "consumer Consumer
interest representative" means:
(A) a residential utility customer or group of
residential utility customers represented by a
not-for-profit group or organization registered with
the Illinois Attorney General under the Solicitation
for Charity Act;
(B) representatives of not-for-profit groups or
organizations whose membership is limited to
residential utility customers; or
(C) representatives of not-for-profit groups or
organizations whose membership includes Illinois
residents and that address the community, economic,

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environmental, or social welfare of Illinois
residents, except government agencies or intervenors
specifically authorized by Illinois law to participate
in Commission proceedings on behalf of Illinois
consumers.
(3) A consumer interest representative is eligible to
receive compensation from the consumer intervenor
compensation fund if its participation included lay or
expert testimony or legal briefing and argument concerning
the expenses, investments, rate design, rate impact, or
other matters affecting the pricing, rates, costs or other
charges associated with utility service, the Commission
adopts a material recommendation related to a significant
issue in the docket, and participation caused a
significant financial cost hardship to the participant;
however, no consumer interest representative shall be
eligible to receive an award pursuant to this Section if
the consumer interest representative receives any
compensation, funding, or donations, directly or
indirectly, from parties that have a financial interest in
the outcome of the proceeding.
(4) Within 30 days after September 15, 2021 (the
effective date of Public Act 102-662), each utility that
files a request for an increase in rates under Article IX
or Article XVI shall deposit an amount equal to one half of
the rate case attorney and expert expense allowed by the

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Commission, but not to exceed $500,000, into the fund
within 35 days of the date of the Commission's Final final
Order in the rate case or 20 days after the denial of
rehearing under Section 10-113 of this Act, whichever is
later. The Consumer Intervenor Compensation Fund shall be
used to provide payment to consumer interest
representatives as described in this Section.
(5) An electric public utility with 3,000,000 or more
retail customers shall contribute $450,000 to the Consumer
Intervenor Compensation Fund within 60 days after
September 15, 2021 (the effective date of Public Act
102-662). A combined electric and gas public utility
serving fewer than 3,000,000 but more than 500,000 retail
customers shall contribute $225,000 to the Consumer
Intervenor Compensation Fund within 60 days after
September 15, 2021 (the effective date of Public Act
102-662). A gas public utility with 1,500,000 or more
retail customers that is not a combined electric and gas
public utility shall contribute $225,000 to the Consumer
Intervenor Compensation Fund within 60 days after
September 15, 2021 (the effective date of Public Act
102-662). A gas public utility with fewer than 1,500,000
retail customers but more than 300,000 retail customers
that is not a combined electric and gas public utility
shall contribute $80,000 to the Consumer Intervenor
Compensation Fund within 60 days after September 15, 2021

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(the effective date of Public Act 102-662). A gas public
utility with fewer than 300,000 retail customers that is
not a combined electric and gas public utility shall
contribute $20,000 to the Consumer Intervenor Compensation
Fund within 60 days after September 15, 2021 (the
effective date of Public Act 102-662). A combined electric
and gas public utility serving fewer than 500,000 retail
customers shall contribute $20,000 to the Consumer
Intervenor Compensation Fund within 60 days after
September 15, 2021 (the effective date of Public Act
102-662). A water or sewer public utility serving more
than 100,000 retail customers shall contribute $80,000,
and a water or sewer public utility serving fewer than
100,000 but more than 10,000 retail customers shall
contribute $20,000.
(6)(A) Prior to the entry of a Final Order in a
docketed case, the Commission Administrator shall provide
a payment to a consumer interest representative that
demonstrates through a verified application for funding
that the consumer interest representative's participation
or intervention without an award of fees or costs imposes
a significant financial hardship based on a schedule to be
developed by the Commission. The Administrator may require
verification of costs incurred, including statements of
hours spent, as a condition to paying the consumer
interest representative prior to the entry of a Final

HB3779 - 447 - LRB104 11172 AAS 21254 b
Order in a docketed case.
(B) If the Commission adopts a material recommendation
related to a significant issue in the docket and
participation caused a financial cost hardship to the
participant, then the consumer interest representative
shall be allowed payment for some or all of the consumer
interest representative's reasonable attorney's or
advocate's fees, reasonable expert witness fees, and other
reasonable costs of preparation for and participation in a
hearing or proceeding. Expenses related to travel or meals
shall not be compensable.
(C) The consumer interest representative shall submit
an itemized request for compensation to the Consumer
Intervenor Compensation Fund, including the advocate's or
attorney's reasonable fee rate, the number of hours
expended, reasonable expert and expert witness fees, and
other reasonable costs for the preparation for and
participation in the hearing and briefing within 30 days
of the Commission's final order after denial or decision
on rehearing, if any.
(7) Administration of the Fund.
(A) The Consumer Intervenor Compensation Fund is
created as a special fund in the State treasury. All
disbursements from the Consumer Intervenor Compensation
Fund shall be made only upon warrants of the Comptroller
drawn upon the Treasurer as custodian of the Fund upon

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vouchers signed by the Executive Director of the
Commission or by the person or persons designated by the
Director for that purpose. The Comptroller is authorized
to draw the warrant upon vouchers so signed. The Treasurer
shall accept all warrants so signed and shall be released
from liability for all payments made on those warrants.
The Consumer Intervenor Compensation Fund shall be
administered by an Administrator that is a person or
entity that is independent of the Commission. The
administrator will be responsible for the prudent
management of the Consumer Intervenor Compensation Fund
and for recommendations for the award of consumer
intervenor compensation from the Consumer Intervenor
Compensation Fund. The Commission shall issue a request
for qualifications for a third-party program administrator
to administer the Consumer Intervenor Compensation Fund.
The third-party administrator shall be chosen through a
competitive bid process based on selection criteria and
requirements developed by the Commission. The Illinois
Procurement Code does not apply to the hiring or payment
of the Administrator. All Administrator costs may be paid
for using monies from the Consumer Intervenor Compensation
Fund, but the Program Administrator shall strive to
minimize costs in the implementation of the program.
(B) The computation of compensation awarded from the
fund shall take into consideration the market rates paid

HB3779 - 449 - LRB104 11172 AAS 21254 b
to persons of comparable training and experience who offer
similar services, but may not exceed the comparable market
rate for services paid by the public utility as part of its
rate case expense.
(C)(1) Recommendations on the award of compensation by
the administrator shall include consideration of whether
the participation raised in good faith Commission adopted
a material recommendation related to a significant issue
in the docket and whether participation caused a
significant financial cost hardship to the participant and
the payment of compensation is fair, just and reasonable.
(2) Recommendations on the award of compensation by
the administrator shall be submitted to the Commission for
approval. Unless the Commission initiates an investigation
within 45 days after the notice to the Commission, the
award of compensation shall be allowed 45 days after
notice to the Commission. Such notice shall be given by
filing with the Commission on the Commission's e-docket
system, and keeping open for public inspection the award
for compensation proposed by the Administrator. The
Commission shall have power, and it is hereby given
authority, either upon complaint or upon its own
initiative without complaint, at once, and if it so
orders, without answer or other formal pleadings, but upon
reasonable notice, to enter upon a hearing concerning the
propriety of the award.

HB3779 - 450 - LRB104 11172 AAS 21254 b
(3) A consumer interest representative who performed
work or otherwise incurred expenses in an eligible
proceeding before the Illinois Commerce Commission prior
to the effective date of this amendatory Act of the 104th
General Assembly and after September 15, 2021 (the
effective date of Public Act 102-662) and who, due to a
denied application or otherwise, were not awarded
compensation for the entirety of these expenses from the
Consumer Intervenor Compensation Fund, may seek
compensation from the Consumer Intervenor Compensation
Fund pursuant to this Section. Nothing in this Section
shall prohibit retroactive awards to eligible
participants, for work performed or expenses incurred in
eligible proceedings prior to the effective date of this
amendatory Act of the 104th General Assembly and after
September 15, 2021 (the effective date of Public Act
102-662). Such applications shall be subject to the
revised eligibility standards enacted pursuant to this
amendatory Act of the 104th General Assembly. Such
applications may be submitted at any time within one
calendar year of the effective date of this amendatory Act
of the 104th General Assembly.
(c) The Commission may adopt rules to implement this
Section.
(Source: P.A. 102-662, eff. 9-15-21; 103-605, eff. 7-1-24.)

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(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
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

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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
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

HB3779 - 453 - LRB104 11172 AAS 21254 b
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; and (x) "electricity provider" and
"electric utility" includes municipalities and municipal power
agencies as defined in Section 11-119.3-1 of the Illinois
Municipal Code and electric cooperatives as defined in Section
3-119 of this Act.
(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
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

HB3779 - 454 - LRB104 11172 AAS 21254 b
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
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

HB3779 - 455 - LRB104 11172 AAS 21254 b
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
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

HB3779 - 456 - LRB104 11172 AAS 21254 b
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
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

HB3779 - 457 - LRB104 11172 AAS 21254 b
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.
(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

HB3779 - 458 - LRB104 11172 AAS 21254 b
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
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

HB3779 - 459 - LRB104 11172 AAS 21254 b
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
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

HB3779 - 460 - LRB104 11172 AAS 21254 b
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
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

HB3779 - 461 - LRB104 11172 AAS 21254 b
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
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

HB3779 - 462 - LRB104 11172 AAS 21254 b
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 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
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

HB3779 - 463 - LRB104 11172 AAS 21254 b
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
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

HB3779 - 464 - LRB104 11172 AAS 21254 b
Interconnection Working Group to focus on specific issues
of importance, as appropriate. 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) create or contract for an Ombudsman to resolve
interconnection disputes through non-binding arbitration.
The 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.
(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

HB3779 - 465 - LRB104 11172 AAS 21254 b
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
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

HB3779 - 466 - LRB104 11172 AAS 21254 b
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
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

HB3779 - 467 - LRB104 11172 AAS 21254 b
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
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

HB3779 - 468 - LRB104 11172 AAS 21254 b
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
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

HB3779 - 469 - LRB104 11172 AAS 21254 b
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
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

HB3779 - 470 - LRB104 11172 AAS 21254 b
community renewable generating project that may not exceed 2%
of the 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 operator of a
community renewable generating project.
(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
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

HB3779 - 471 - LRB104 11172 AAS 21254 b
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
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

HB3779 - 472 - LRB104 11172 AAS 21254 b
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
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.

HB3779 - 473 - LRB104 11172 AAS 21254 b
(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. 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
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

HB3779 - 474 - LRB104 11172 AAS 21254 b
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
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

HB3779 - 475 - LRB104 11172 AAS 21254 b
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
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

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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
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

HB3779 - 477 - LRB104 11172 AAS 21254 b
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
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

HB3779 - 478 - LRB104 11172 AAS 21254 b
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
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

HB3779 - 479 - LRB104 11172 AAS 21254 b
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
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.

HB3779 - 480 - LRB104 11172 AAS 21254 b
(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
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.

HB3779 - 481 - LRB104 11172 AAS 21254 b
"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
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

HB3779 - 482 - LRB104 11172 AAS 21254 b
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
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

HB3779 - 483 - LRB104 11172 AAS 21254 b
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
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

HB3779 - 484 - LRB104 11172 AAS 21254 b
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
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

HB3779 - 485 - LRB104 11172 AAS 21254 b
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. 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.
(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

HB3779 - 486 - LRB104 11172 AAS 21254 b
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 a Virtual Power Plant Program defined in Section
16.107.9 an a peak time rebate program, hourly pricing
program, or time-of-use rate program offered by the
applicable electric utility. 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.
(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

HB3779 - 487 - LRB104 11172 AAS 21254 b
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.
(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.

HB3779 - 488 - LRB104 11172 AAS 21254 b
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
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

HB3779 - 489 - LRB104 11172 AAS 21254 b
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
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,

HB3779 - 490 - LRB104 11172 AAS 21254 b
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
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

HB3779 - 491 - LRB104 11172 AAS 21254 b
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
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

HB3779 - 492 - LRB104 11172 AAS 21254 b
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
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

HB3779 - 493 - LRB104 11172 AAS 21254 b
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
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

HB3779 - 494 - LRB104 11172 AAS 21254 b
(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.
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

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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
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

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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
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

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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
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

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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
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 5/16-107.7A new)
Sec. 16-107.7A. PJM capacity auction bill impacts.

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(a) The recent results of PJM capacity auctions will
affect the market prices paid by customers. Load growth,
electric supply constraints, and PJM capacity auction rules
have resulted in increased PJM capacity prices for the
2025-2026 PJM delivery year, which will increase the rates
paid by customers beginning for the June 1, 2025 billing
cycle.
(b) To promote bill transparency, electric utilities
serving customers located in the PJM interconnection region
shall include at least the following statement as part of a
bill insert or bill message provided with any bill issued to
any customers for whom the electric utility provides energy
supply: "The energy charges on your bill have increased this
month due to increased capacity prices resulting from PJM
capacity auctions. These costs are not related to your
utility's delivery services".
(c) The electric utility's obligation to reflect the
information required by this subsection shall begin with the
June 1, 2025 billing cycle, and shall not continue past the
December 2025 billing period.
(220 ILCS 5/16-107.8 new)
Sec. 16-107.8. Residential time-of-use pricing.
(a) The General Assembly finds that time-of-use rates and
pricing plans can lower energy costs for consumers and reduce
grid costs as well as help the State achieve its energy policy

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goals by improving load shape, encouraging energy
conservation, and shifting usage away from periods where
fossil fuels are used to meet peak demand. Further, by
providing consumers information relating the costs of service
to the time of energy usage, time-of-use rates can help
consumers reduce their energy bills by using electricity when
it is less costly. Time-of-use rates can help allocate
electricity system costs more accurately and thus equitably to
those who cause costs. Such rates can reduce the need for
ramping resources and increase the grid's ability to
cost-effectively integrate greater quantities of variable
renewable energy and distributed energy resources.
(b) An electric utility that has a tariff approved under
subsection (d) of Section 16-108.18 within one year of this
amendatory Act of the 104th General Assembly shall also offer
at least one market-based, residential rate for eligible
retail customers that choose to take power and energy supply
service from the utility. If the utility has a pending request
for approval of a Multi-Year Integrated Grid Plan, the utility
shall update its filing in that docket to reflect the likely
impacts of the time-of-use rate offering. The utility shall
file its time-of-use rate tariff no later than 120 days after
the effective date of this amendatory Act of the 104th General
Assembly, and each utility subject to this requirement shall
implement the requirements of this subsection by filing a
tariff with the Commission. The tariff or tariffs shall be

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subject to the following provisions:
(1) If more than one tariff is proposed, at least one
tariff shall include at least 3 time blocks: a peak time
block, defined as 2 p.m. to 7 p.m. on nonholiday weekdays
or the 5 consecutive hours best reflecting the highest
system peak demands; an off-peak time block, defined as 10
a.m. to 2 p.m. and 7 p.m. to 10 p.m. on nonholiday weekdays
or the 7 total hours occurring in some combination before
and after the peak period, which reflect the next highest
system peak demands; and a super-off-peak time block,
defined as all other hours and including weekend days.
(2) This tariff shall strive to achieve price ratios
between the blocks as follows: the super-off-peak time
block price shall be no less than zero but no greater than
one-half of the price of the off-peak time block price,
and the off-peak time block price shall be no greater than
one-half of the price of the peak time block price.
(3) The time-of-use rate shall include the costs of
procuring power and energy pursuant to the Illinois Power
Agency procurement process that occurs under Section
16-111.5 of this Act.
(4) Adjustments to the charges set by the tariff may
be made on a semi-annual basis, as follows: each May and
November, the utility shall submit to the Commission,
through an informational filing, its updated charges, and
such charges shall take effect beginning with the June

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monthly billing period and December monthly billing
period, respectively.
(5) The tariff shall include a purchased energy
adjustment to fully recover the supply costs for the
customers taking service under this tariff.
As used in this subsection, "eligible residential
customers" includes, but is not limited to, customers
participating in net electricity metering under the terms of
Section 16-107.5. Anything in Section 16-107.5
notwithstanding, energy credits for net-metering customers
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 time-of-use period.
(c) The Commission shall, after notice and hearing,
approve the tariff or tariffs with modifications the
Commission finds necessary to improve the program design,
customer participation in the program, or coordination with
existing utility pricing programs, energy efficiency programs,
demand-response programs, and any other programs supporting
State energy policy goals and the integration of distributed
energy resources. The Commission shall also consider how the
proposed time-of-use rate design reflects the system costs and
usage patterns of the utility. A proceeding under this
subsection may not exceed 120 days in length.
(d) If the Commission issues an order pursuant to this
subsection, the affected electric utility shall contract with

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an entity not affiliated with the electric utility to serve as
a program administrator to develop and implement a program to
provide consumer outreach, enrollment, and education
concerning time-of-use pricing and to establish and administer
an information system and technical and other customer
assistance that is necessary to enable customers to manage
electricity use. The program administrator: (i) shall be
selected and compensated by the electric utility, subject to
Commission approval; (ii) shall have demonstrated technical
and managerial competence in the development and
administration of demand management programs; and (iii) may
develop and implement risk management, energy efficiency, and
other services related to energy use management for which the
program administrator shall be compensated by participants in
the program receiving such services. The electric utility
shall provide the program administrator with all information
and assistance necessary to perform the program
administrator's duties, including, but not limited to,
customer, account, and energy use data. The electric utility
shall permit the program administrator to include inserts in
residential customer bills 2 times per year to assist with
customer outreach and enrollment. The program administrator
shall submit an annual report to the electric utility no later
than April 1 of each year describing the operation and results
of the program, including information concerning the number
and types of customers using the program, changes in

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customers' energy use patterns, an assessment of the value of
the program to both participants and nonparticipants, and
recommendations concerning modification of the program and the
tariff or tariffs filed under this Section. This report shall
be filed by the electric utility with the Commission within 30
days after receipt and shall be available to the public on the
Commission's website.
(e) Once the tariff or tariffs has been in effect for 12
months, the Commission may, upon complaint, petition, or its
own initiative, open a proceeding to investigate whether
changes or modifications to the tariff or tariffs, program
administration and any other program design element is
necessary to achieve the goals described in subsection (a) and
to shifting usage away from periods where fossil fuels are
used to meet peak demand and realign usage to periods when
renewable generation is available. Such a proceeding may not
last more than 180 days from the date upon which the
investigation is opened by Commission order. Thereafter, the
Commission may, upon complaint, petition, or its own
initiative, open a proceeding to investigate changes or
modifications to the tariff or tariffs at any time the
Commission deems reasonable in order to achieve these
objectives.
(f) An electric utility shall be entitled to recover
reasonable costs incurred in complying with this Section, if
the recovery of the costs is fairly apportioned among its

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residential customers.
(g) The electric utility's tariff or tariffs filed
pursuant to this Section shall be subject to the provisions of
Article IX of this Act insofar as they do not conflict with
this Section.
(h) This Section does not apply to any electric utility
providing service to 100,000 or fewer customers.
(220 ILCS 5/16-107.9 new)
Sec. 16-107.9. Virtual power plant program.
(a) As used in this Section:
"Aggregator" means a third-party entity that enrolls
customers in the program and coordinates the operation of
enrolled devices. An aggregator is a participant in the
program.
"Battery" means a behind-the-meter energy storage device
and associated equipment that operate together to fulfill
program requirements.
"Commission" means the Illinois Commerce Commission.
"Customer" means an active electric service account holder
of a utility.
"Direct participant" means a customer that enrolls in the
program directly with the utility, rather than via an
aggregator.
"Distributed energy resource" has the meaning set forth in
Section 16-107.6.

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"Eligible device" means a customer or third party-owned
distributed energy resource that meets the requirements for
participation in the program as specified in the relevant
program rider.
"Emergency event" means an event called by the utility
with fewer than 24 hours notice.
"Enrolled customer" means a Customer that participates in
the program through either an aggregator or as a direct
participant.
"Enrolled device" means an enrolled customer's eligible
device, as specified in the relevant tariff.
"Grid event" means a grid condition for which the utility
schedules or remotely dispatches enrolled devices to respond
to, as specified in the grid service opportunities for each
tariff.
"Grid service" means a capacity, energy, or ancillary
service that supports grid operations. Such services are
"additive services" pursuant to 220 ILCS 5/16-107.6.
"Low-moderate income qualified customer" means any
resident of a Qualifying Census Tract (QCT) according to the
Department of Housing and Urban Development (HUD. In the event
the Commission cannot make reference to residents of a
Qualifying Census Tract, the Commission shall use the
definition of "low-income households" as defined in Section
1-56 of the Illinois Power Agency Act.
"Participant" means an aggregator or a direct participant.

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"Performance payment" means a payment made to the
participant based on the performance of an enrolled device(s)
providing a grid service during a grid event.
"Performance payment rate" means the compensation rate
paid to participants for providing a particular grid service
during a grid event.
"Program Rider(s)" means one or more of the battery rider,
the non-battery rider, the electric vehicle rider, and such
other virtual power plant program riders as the Commission may
approve from time to time.
"Upfront payment" means a one-time payment made at the
time of enrollment.
"Virtual power plant" means an aggregation of
behind-the-meter distributed energy resources operated in
coordination to provide one or more grid services.
(b) The General Assembly finds that:
(1) virtual power plants are dynamic load management
and energy supply resources that can support grid
operations, reduce ratepayer costs, and achieve other
important public policy goals.
(2) Virtual power plants can reduce demand for grid
supplied electricity during peak periods, shift
electricity consumption out of peak periods, make
renewable energy generated during off-peak periods
available for use during on-peak periods, supply energy to
the grid at desired times, provide frequency regulation,

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voltage support, and other ancillary services, improve
system resiliency and reliability, and provide other grid
services.
(3) Virtual power plants can facilitate and optimize
the utilization of electrical generation from wind and
solar energy to help utilities increase hosting capacity
and integrate more renewable energy resources.
(4) Virtual power plants can reduce costs to
ratepayers by utilizing customer-sited resources to
provide grid services, avoiding or reducing reliance on
fossil-fuel fired peaker plants, avoiding or deferring the
need to construct new and more costly grid scale
resources, optimizing the use of existing assets, and
avoiding or deferring distribution and transmission system
upgrades and other grid investments.
(5) Virtual power plants can promote equity by
reducing costs for all ratepayers, expanding access to
distributed energy resources among low- and
moderate-income customers through improved distributed
energy resource financeability, and providing other
important co-benefits, including reduction in emissions of
greenhouse gasses and other pollutants, especially in
environmental justice and other disadvantaged communities
that host fossil fuel generation plants.
(6) The United States Department of Energy estimates
that the United States could deploy 80-160 gigawatts of

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virtual power plants by 2030 (a tripling of current
levels) to support the rapid electrification of vehicles
and homes and provide on the order of $10 billion in
ratepayer savings annually. The deployment of virtual
power plants can provide energy cost savings and other
benefits to the people of Illinois.
(7) There are significant barriers to deployment and
operation of virtual power plants, including the need for
statutory and regulatory guidance and support, greater
consistency in virtual power plant programs across
regulatory jurisdictions, and for utility commitments to
incorporate the use of virtual power plants into system
operations and long-term resource planning.
(8) It is in the public interest to advance customer
choice and leverage the expertise of private, non-utility
entities to advance innovation and implement
cost-effective clean energy solutions.
(9) The policy of Illinois shall be to maximize the
use of virtual power plants comprised of customer-owned
and third party-owned distributed energy resources to
deliver system services and other benefits through utility
administered virtual power plant programs in accordance
with the provisions of this amendatory Act of the 104th
General Assembly.
(c) Within 120 days after the effective date of this
amendatory Act of the 104th General Assembly, each electric

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utility serving more than 300,000 customers as of January 1,
2025, shall develop and file with the Commission a virtual
power plant program proposal consistent with the provisions of
this Section. The Commission shall provide opportunities for
stakeholders to provide input on the virtual power plant
programs proposed for implementation by each utility, which
the Commission shall take into consideration in its review of
each utility's filing. Within 120 days of the utility's
filing, the Commission shall approve or modify and approve
each utility's virtual power plant program proposal for
immediate implementation by the utility.
(d) The virtual power plant program filed pursuant to
subsection (c) of this section shall be developed for
implementation through a standard offer, open access tariff
for distributed energy resources to provide system peak load
reduction and other grid services. The virtual power plant
program tariff shall:
(1) Allow for customers with battery storage,
non-battery storage and electric vehicle technologies to
enroll their respective devices in the program under
separate service riders for each technology type through
aggregators or directly with the utility. The tariff filed
pursuant to subsection (c) of this section shall at
minimum include a rider for new and existing battery
storage devices and shall incorporate additional riders
for non-battery storage devices and electric vehicles no

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later than one year after the approval of the virtual
power plant program approved in subsection (c).
(2) Where feasible, provide a mechanism to incorporate
existing programs, such as smart thermostat demand
response or electric vehicle charging programs currently
offered by the utility, into the respective technology
riders for operation under the virtual power plant program
framework;
(3) Include grid services opportunities for each
eligible technology that customers and aggregators may
provide, which shall include, at minimum,reduction to the
utility's applicable capacity and transmission obligations
and daily wholesale energy arbitrage opportunities through
provision of grid services, and may also include:
(i) clean peak service;
(ii) local peak demand reduction;
(iii) locational value;
(iv) the avoidance or deferral of transmission
or distribution upgrades or capacity expansion;
(v) voltage support and other ancillary
services;
(vi) emergency services; and
(vii) such other functions and grid service
opportunities that the Commission determines are
supportive of efficient planning and operation of
the electrical grid.

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(4) Provide operational parameters for each eligible
program rider and grid service, which shall include at
minimum:
(i) minimum and maximum numbers of grid events
for which the utility may dispatch the enrolled
distributed energy resources;
(ii) months of the year that grid events may
occur;
(iii) days of the week that grid events may
occur;
(iv) times of day that grid events may occur;
(v) maximum duration of grid events;
(vi) minimum day-ahead advance notification
requirement of grid events, except for emergency
events, as applicable.
(5) Include provisions for aggregators to participate
in the virtual power plant program, automatically enroll
and manage their customers' participation, receive
dispatch signals and other communications from the
utility, deliver performance measurement and verification
data to the utility, and receive virtual power plant
program payments directly from the utility;
(6) Include provisions for direct participant
customers to enroll and participate directly with the
utility, receive dispatch signals and other communications
from the utility, deliver performance measurement and

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verification data to the utility, and receive virtual
power plant program payments directly from the utility.
Any provisions implementing this subpart that necessitate
the installation of equipment to enable direct
participation via the utility shall apply to Customers who
elect to participate as a direct participant and shall not
be required of customers who participate via an aggregator
or to customers who do not participate in the virtual
power plant program.
(7) Provide for measurement and verification of
battery performance directly at the device without the
requirement for the installation of an additional meter;
and provide such other measurement standards for
non-battery and electric vehicle technologies for approval
by the Commission.
(8) Include upfront payment and performance payment
compensation mechanisms for the battery rider system peak
reduction service. The performance payment shall be based
on the average capacity provided during grid events. The
Commission shall approve additional compensation
mechanisms as it determines appropriate for other grid
services provided under the battery, non-battery and
electric vehicle riders. The virtual power plant program
shall not assess penalties for non-performance; however,
the Commission may approve reasonable mechanisms to
disenroll customers for continued non-performance.

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(9) Low-to-moderate income customers, and customers
located in environmental justice and other disadvantaged
communities or customer classes as the Commission may
designate shall receive a higher upfront payment in
addition to performance payments. The Commission shall
coordinate with state energy officials and departments to
make funding from the federal Inflation Reduction Act and
such other sources as may be available for use in
providing higher upfront payments to customers classes as
may be approved by the Commission in accordance with this
subsection.
(10) The Commission shall determine the value of grid
service opportunities based on the National Standards
Practice Manual for Benefit Cost Analysis of Distributed
Energy Resources. The Commission shall take this value
into account when establishing the upfront payment and
performance payment under subsection (8) of this section.
(11) Allow participants to lock in the performance
payment rate applicable at the time of enrollment for a
minimum of five years, after which time the participant
may reenroll at the then applicable performance payment
rate for an additional five-year term;
(12) in addition to the compensation for each grid
service, the tariff shall provide that energy exported
from a participating distributed energy resource shall be
credited to the enrolled customer at a value equal to the

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retail rate charged by the utility for energy at the time
of the export, irrespective of the export compensation
rate specified in the customer's underlying
interconnection tariff. Nothing in this section shall
affect the rate of compensation for energy that is
exported outside of a grid event under a
Commission-approved virtual power plant program.
(13) Enrolled customers may co-participate in any
applicable underlying interconnection tariff and may
provide multiple grid services and/or co-participate in
other riders under the virtual power plant program, or
other grid service programs outside the virtual power
plant program, including wholesale market programs, except
as otherwise provided by the Commission. Enrolled
customers shall remain eligible to receive state and
federal incentives in addition to any compensation
received for participating in the virtual power plant
program. Crediting for exported energy shall not
constitute double counting.
(14) The Commission may adopt other reasonable
requirements for participation consistent with this
subsection; provided that collateral from a direct
participant or an aggregator shall not be required for
participation.
(e) Utility-owned resources shall not be eligible to
participate in the virtual power plant program. Utilities and

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utility affiliates may not be aggregators. Except that
utilities may develop bundled supply, delivery, and virtual
power plant rates that incentivize grid beneficial behavior
that captures grid opportunities.
(f) The utility may contract with a third party
distributed energy resource management system provider to
assist with program implementation provided that
implementation shall not be delayed due to the lack of
utility-owned distributed energy resource management system
capabilities or third party distributed energy resource
management system capabilities.
(g) Utilities may seek to recover prudently incurred costs
to facilitate the virtual power plant program approved
pursuant to subsection (c), including but not limited to:
distributed energy resource management system provider and
other service contract costs, operations and maintenance
expenses, information technology costs, and such other costs,
expenses and investments the Commission finds necessary and
prudent for the development and implementation of the program.
(h) The provisions of subsection (g) of this Section
notwithstanding, the utility shall recover the cost of virtual
power plant program upfront payments and performance payments
and such other payments made to participants through cost
recovery mechanisms approved by the Commission. The Commission
may at its discretion allow a reasonable rate of return on the
cost of payments made for the provision of grid services and

HB3779 - 517 - LRB104 11172 AAS 21254 b
such other costs approved by the Commission and shall take any
such allowance into consideration when considering performance
incentives pursuant to subsection (j).
(i) The Commission shall initiate a proceeding to develop
capacity procurement targets applicable to the utility for the
utilization of the virtual power plant program with
corresponding performance incentives for achieving the
established targets in accordance with the provisions of this
section.
(j) Within 270 days of the effective date of this Act the
Commission shall, at minimum:
(1) establish annual capacity procurement and
performance targets for the system peak reduction service,
which shall be designed to meaningfully increase
year-over-year the amount of capacity procured for system
peak reduction over a five year period. The Commission
shall establish corresponding performance incentives for
achieving the target established for each year of the
performance period.
(2) the performance incentives established pursuant to
paragraph (1) of this subsection shall include financial
rewards for achieving the targets and may include
financial penalties for failure to achieve the targets.
(3) the Commission shall establish new targets for
subsequent 5-year periods.
(4) the performance targets and incentives established

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pursuant to this section shall take effect no later than
the beginning of the second calendar year following the
year in which the Commission approves a utility's virtual
power plant program pursuant to subsection (c) of this
Section.
(k) The Commission shall develop targets and performance
incentives for additional grid services adopted pursuant to
subsection (d) of this Section no later than 270 days after
such additional grid services are approved for implementation
through the tariff, which shall take effect no later than the
beginning of the second calendar year following the year in
which the Commission approves such additional grid services.
(l) Each utility shall file an annual report no later than
January 31 of each year that shall include, at minimum: the
total capacity enrolled in each program rider developed
pursuant to the requirements of Section, broken out by
technology type, customer class, and aggregator and direct
participant status for each grid service opportunity offered
in the prior calendar year along with recommendations to
increase participation in the virtual power plant program, and
such other information as the Commission may require from time
to time.
(m) Each utility shall amend existing tariffs and
procedures that limit customers' ability to participate in
providing grid services under this program such as limitations
on charging energy storage devices with grid energy or

HB3779 - 519 - LRB104 11172 AAS 21254 b
exporting energy to the grid from battery discharge.
(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
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

HB3779 - 520 - LRB104 11172 AAS 21254 b
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
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

HB3779 - 521 - LRB104 11172 AAS 21254 b
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
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

HB3779 - 522 - LRB104 11172 AAS 21254 b
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
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

HB3779 - 523 - LRB104 11172 AAS 21254 b
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
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

HB3779 - 524 - LRB104 11172 AAS 21254 b
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,
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

HB3779 - 525 - LRB104 11172 AAS 21254 b
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
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

HB3779 - 526 - LRB104 11172 AAS 21254 b
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;
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

HB3779 - 527 - LRB104 11172 AAS 21254 b
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
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

HB3779 - 528 - LRB104 11172 AAS 21254 b
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
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

HB3779 - 529 - LRB104 11172 AAS 21254 b
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
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

HB3779 - 530 - LRB104 11172 AAS 21254 b
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
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

HB3779 - 531 - LRB104 11172 AAS 21254 b
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
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

HB3779 - 532 - LRB104 11172 AAS 21254 b
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
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

HB3779 - 533 - LRB104 11172 AAS 21254 b
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
(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

HB3779 - 534 - LRB104 11172 AAS 21254 b
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
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.
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
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

HB3779 - 535 - LRB104 11172 AAS 21254 b
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
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

HB3779 - 536 - LRB104 11172 AAS 21254 b
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
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

HB3779 - 537 - LRB104 11172 AAS 21254 b
(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
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,

HB3779 - 538 - LRB104 11172 AAS 21254 b
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.
The electric utility shall be entitled to recover through
tariffed charges all of the costs associated with the
procurement of energy storage resources to meet the
requirements of Section 1-93 of the Illinois Power Agency Act
under energy storage procurement plans as approved in
accordance with that Section and Section 16-111.5 of this Act.
These costs shall include the costs of procuring energy
storage resources and the reasonable costs that the utility
incurs as part of the procurement processes and implementing
and complying with energy storage procurement plans and
processes approved by the Commission. The costs associated
with the procurement of energy storage resources shall be
allocated across all retail customers in proportion to the
energy storage resources the electric utility procures for the
customers through a single, uniform cents per kilowatt-hour

HB3779 - 539 - LRB104 11172 AAS 21254 b
charge applicable to the retail customers, which shall appear
as a separate line item on each customer's bill.
(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
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

HB3779 - 540 - LRB104 11172 AAS 21254 b
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.
(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

HB3779 - 541 - LRB104 11172 AAS 21254 b
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
(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).

HB3779 - 542 - LRB104 11172 AAS 21254 b
(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
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 5/16-108.30)
Sec. 16-108.30. Energy Transition Assistance Fund.
(a) The Energy Transition Assistance Fund is hereby
created as a special fund in the State Treasury. The Energy
Transition Assistance Fund is authorized to receive moneys
collected pursuant to this Section. Subject to appropriation,
the Department of Commerce and Economic Opportunity shall use
moneys from the Energy Transition Assistance Fund consistent
with the purposes of this Act.
(b) An electric utility serving more than 500,000
customers in the State shall assess an energy transition
assistance charge on all its retail customers for the Energy
Transition Assistance Fund. The utility's total charge shall
be set based upon the value determined by the Department of

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Commerce and Economic Opportunity pursuant to subsection (d)
or (e), as applicable, of Section 605-1075 of the Department
of Commerce and Economic Opportunity Law of the Civil
Administrative Code of Illinois. For each utility, the charge
shall be recovered through a single, uniform cents per
kilowatt-hour charge applicable to all retail customers. For
each utility, the charge shall not exceed 1.3% of the amount
paid per kilowatthour by eligible retail customers during the
year ending May 31, 2009.
(c) Within 75 days of the effective date of this
amendatory Act of the 102nd General Assembly, each electric
utility serving more than 500,000 customers in the State shall
file with the Illinois Commerce Commission tariffs
incorporating the energy transition assistance charge in other
charges stated in such tariffs, which energy transition
assistance charges shall become effective no later than the
beginning of the first billing cycle that begins on or after
January 1, 2022. Each electric utility serving more than
500,000 customers in the State shall, prior to the beginning
of each calendar year starting with calendar year 2023, file
with the Illinois Commerce Commission tariff revisions to
incorporate annual revisions to the energy transition
assistance charge as prescribed by the Department of Commerce
and Economic Opportunity pursuant to Section 605-1075 of the
Department of Commerce and Economic Opportunity Law of the
Civil Administrative Code of Illinois so that such revision

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becomes effective no later than the beginning of the first
billing cycle in each respective year. Within 75 days of the
effective date of this amendatory Act of the 104th General
Assembly, each electric utility serving more than 500,000
customers in the State shall file with the Illinois Commerce
Commission tariffs incorporating the additional energy
transition charge required under this amendatory Act, which
additional energy transition assistance charges shall become
effective no later than the beginning of the first billing
cycle that begins on or after September 1, 2025.
(d) The energy transition assistance charge shall be
considered a charge for public utility service.
(e) By the 20th day of the month following the month in
which the charges imposed by this Section were collected, each
electric utility serving more than 500,000 customers in the
State shall remit to Department of Revenue all moneys received
as payment of the energy transition assistance charge on a
return prescribed and furnished by the Department of Revenue
showing such information as the Department of Revenue may
reasonably require. If a customer makes a partial payment, a
public utility may apply such partial payments first to
amounts owed to the utility. No customer may be subjected to
disconnection of his or her utility service for failure to pay
the energy transition assistance charge.
If any payment provided for in this subsection exceeds the
electric utility's liabilities under this Act, as shown on an

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original return, the Department may authorize the electric
utility to credit such excess payment against liability
subsequently to be remitted to the Department under this Act,
in accordance with reasonable rules adopted by the Department.
All the provisions of Sections 4, 5, 5a, 5b, 5c, 5d, 5e,
5f, 5g, 5i, 5j, 6, 6a, 6b, 6c, 7, 8, 9, 10, 11, 11a, 12, and 13
of the Retailers' Occupation Tax Act that are not inconsistent
with this Act apply, as far as practicable, to the charge
imposed by this Act to the same extent as if those provisions
were included in this Act. References in the incorporated
Sections of the Retailers' Occupation Tax Act to retailers, to
sellers, or to persons engaged in the business of selling
tangible personal property mean persons required to remit the
charge imposed under this Act.
(f) The Department of Revenue shall deposit into the
Energy Transition Assistance Fund all moneys remitted to it in
accordance with this Section.
(g) The Department of Revenue may establish such rules as
it deems necessary to implement this Section.
(h) The Department of Commerce and Economic Opportunity
may establish such rules as it deems necessary to implement
this Section.
(Source: P.A. 102-662, eff. 9-15-21; 102-1031, eff. 5-27-22.)
(220 ILCS 5/16-111.5)
Sec. 16-111.5. Provisions relating to procurement.

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(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, 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 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

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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 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

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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.
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;

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(ii) switching trends and competitive retail
market analysis;
(iii) known or projected changes to future loads;
and
(iv) growth forecasts by customer class.
(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,
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

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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
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;

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(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
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; however, nothing in this item (iv) precludes
consideration of long-term contracts with a length up
to and including 20 years for clean energy, as defined
in Section 1-10 of the Illinois Power Agency Act, with
an appropriate portion of the portfolio to be

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allocated to such long-term contracts;
(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
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; and.
(vii) for procurement events beginning after May
31, 2025, consideration of whether products offered

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into the procurement process are renewable energy
resources, as defined in Section 1-10 of the Illinois
Power Agency Act that might otherwise qualify for the
renewable portfolio standard described in
subparagraphs (c)(1)(I) and (c)(1)(J) of Section 1-75
of the Illinois Power Agency Act where such product or
products can be procured at or near the price of
nonrenewable energy after taking account of the social
cost of carbon as set forth in subparagraph (B) of
paragraph (1) of subsection (d-5) of Section 1-75 of
the Illinois Power Agency Act. The Agency shall
consider fuel volatility, long-term trends in
non-renewable energy resource pricing, and the
environmental benefits of renewable energy resources
when comparing products and may, in doing so, select
products comprised of renewable energy resources that
are at a higher fixed price over a longer duration.
Each product procured shall include all environmental
attributes, including, but not limited to, and
renewable energy credits, all as defined in Section
1-10 of the Illinois Power Agency Act, and all
credits, characteristics, benefits, emissions
reductions, offsets, and allowances, howsoever
entitled, attributable to the generation of the
product procured or its displacement of generation.
(4) Proposed procedures for balancing loads. The

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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
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

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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
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

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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
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

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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
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

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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
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

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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)
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

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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
procurement process and any recommendations for
change.
(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

HB3779 - 561 - LRB104 11172 AAS 21254 b
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.
(b-10) Capacity procurement.
(1) Definitions. For purposes of this subsection:
"Applicable Local Resource Zone" means the Zone 4
Local Resource Zone as set forth in the MISO Business
Practices Manual 011 - Resource Adequacy, or any future
successor zone for the same geographic space, as
designated by MISO governing documents.
"Applicable locational deliverability area" means the
ComEd Locational Deliverability Area as set forth in the
PJM Manual, or any future successor area for the same
geographic space, as designated by PJM governing
documents.
"Electric cooperative" has the meaning given to that
term in Section 3-119.
"Fixed Resource Adequacy Plan", "Local Clearing
Requirement", "Local Resource Zone", "Planning Resource",
and "Planning Reserve Margin Requirement" have the
meanings given to those terms in the MISO Tariff,
including as they may apply to individual Load Serving
Entities, as applicable. For avoidance of doubt, these
terms shall be interpreted as multiple seasonal values
within a given delivery year if MISO's then-prevailing

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resource adequacy construct has a seasonal component.
"Load Serving Entity" has the meaning given to that
term by the regional transmission organization where the
entity serves customers, either in the Midcontinent
Independent System Operator Tariff or PJM Interconnection,
LLC Reliability Assurance Agreement.
(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

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following Commission approval of the procurement plan;
(ii) develop benchmarks in accordance with
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;

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(viii) maintain confidentiality of supplier and
bidding information in a manner consistent with all
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

HB3779 - 565 - LRB104 11172 AAS 21254 b
bidding information in a manner consistent with all
applicable laws, rules, regulations, and tariffs;
(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

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such other date as may be required by the Commission. The
procurement plan shall identify the portfolio of
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.

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(3) Within 5 days after the filing of the procurement
plan, any person objecting to the procurement plan shall
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

HB3779 - 568 - LRB104 11172 AAS 21254 b
energy facilities to be constructed, the amounts of
renewable energy credits to be delivered pursuant to the
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.

HB3779 - 569 - LRB104 11172 AAS 21254 b
(2) Standard contract forms and credit terms and
instruments. The procurement administrator, in
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. 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
final prices in the contracts for each of the products

HB3779 - 570 - LRB104 11172 AAS 21254 b
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.
(i) Event of supplier default: In the event of

HB3779 - 571 - LRB104 11172 AAS 21254 b
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
requirement due to insufficient supplier participation

HB3779 - 572 - LRB104 11172 AAS 21254 b
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
day-ahead or real time energy, or both; provided,

HB3779 - 573 - LRB104 11172 AAS 21254 b
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 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
within 2 business days after receipt of the reports.
(g) Within 3 business days after the Commission decision

HB3779 - 574 - LRB104 11172 AAS 21254 b
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.
The Commission, the procurement monitor, the procurement
administrator, the Illinois Power Agency, and all participants

HB3779 - 575 - LRB104 11172 AAS 21254 b
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.
(i) Within 2 business days after a Commission decision
approving the results of a procurement event or such other
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

HB3779 - 576 - LRB104 11172 AAS 21254 b
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.
(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

HB3779 - 577 - LRB104 11172 AAS 21254 b
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).
(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

HB3779 - 578 - LRB104 11172 AAS 21254 b
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
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

HB3779 - 579 - LRB104 11172 AAS 21254 b
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
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).

HB3779 - 580 - LRB104 11172 AAS 21254 b
(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
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

HB3779 - 581 - LRB104 11172 AAS 21254 b
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
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

HB3779 - 582 - LRB104 11172 AAS 21254 b
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
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

HB3779 - 583 - LRB104 11172 AAS 21254 b
distributed renewable energy generation devices.
(Source: P.A. 102-662, eff. 9-15-21.)
(220 ILCS 5/16-115A)
Sec. 16-115A. Obligations of alternative retail electric
suppliers.
(a) An alternative retail electric supplier:
(i) shall comply with the requirements imposed on
public utilities by Sections 8-201 through 8-207, 8-301,
8-505 and 8-507 of this Act, to the extent that these
Sections have application to the services being offered by
the alternative retail electric supplier;
(ii) shall continue to comply with the requirements
for certification stated in subsection (d) of Section
16-115;
(iii) by May 31, 2020 and every June 30 thereafter,
shall submit to the Commission and the Office of the
Attorney General the rates the retail electric supplier
charged to residential customers in the prior year,
including each distinct rate charged and whether the rate
was a fixed or variable rate, the basis for the variable
rate, and any fees charged in addition to the supply rate,
including monthly fees, flat fees, or other service
charges; and
(iv) shall make publicly available on its website,
without the need for a customer login, rate information

HB3779 - 584 - LRB104 11172 AAS 21254 b
for all of its variable, time-of-use, and fixed rate
contracts currently available to residential customers,
including, but not limited to, fixed monthly charges,
early termination fees, and kilowatt-hour charges; and
(v) shall retire all renewable energy credits, as
defined in Section 1-10 of the Illinois Power Agency Act,
and any other environmental attributes of the energy
supply procured from renewable energy resources in
compliance with subsection (h) of this Section.
(b) An alternative retail electric supplier shall obtain
verifiable authorization from a customer, in a form or manner
approved by the Commission consistent with Section 2EE of the
Consumer Fraud and Deceptive Business Practices Act, before
the customer is switched from another supplier.
(c) No alternative retail electric supplier, or electric
utility other than the electric utility in whose service area
a customer is located, shall (i) enter into or employ any
arrangements which have the effect of preventing a retail
customer with a maximum electrical demand of less than one
megawatt from having access to the services of the electric
utility in whose service area the customer is located or (ii)
charge retail customers for such access. This subsection shall
not be construed to prevent an arms-length agreement between a
supplier and a retail customer that sets a term of service,
notice period for terminating service and provisions governing
early termination through a tariff or contract as allowed by

HB3779 - 585 - LRB104 11172 AAS 21254 b
Section 16-119.
(d) An alternative retail electric supplier that is
certified to serve residential or small commercial retail
customers shall not:
(1) deny service to a customer or group of customers
nor establish any differences as to prices, terms,
conditions, services, products, facilities, or in any
other respect, whereby such denial or differences are
based upon race, gender or income, except as provided in
Section 16-115E.
(2) deny service to a customer or group of customers
based on locality nor establish any unreasonable
difference as to prices, terms, conditions, services,
products, or facilities as between localities.
(3) warrant that it has a residential customer or
small commercial retail customer's express consent
agreement to access interval data as described in
subsection (b) of Section 16-122, unless the alternative
retail electric supplier has:
(A) disclosed to the consumer at the outset of the
offer that the alternative retail electric supplier
will access the consumer's interval data from the
consumer's utility with the consumer's express
agreement and the consumer's option to refuse to
provide express agreement to access the consumer's
interval data; and

HB3779 - 586 - LRB104 11172 AAS 21254 b
(B) obtained the consumer's express agreement for
the alternative retail electric supplier to access the
consumer's interval data from the consumer's utility
in a separate letter of agency, a distinct response to
a third-party verification, or as a separate
affirmative consent during a recorded enrollment
initiated by the consumer. The disclosure by the
alternative retail electric supplier to the consumer
in this Section shall be conducted in, translated
into, and provided in a language in which the consumer
subject to the disclosure is able to understand and
communicate.
(4) release, sell, license, or otherwise disclose any
customer interval data obtained under Section 16-122 to
any third person except as provided for in Section 16-122
and paragraphs (1) through (4) of subsection (d-5) of
Section 2EE of the Consumer Fraud and Deceptive Business
Practices Act.
(e) An alternative retail electric supplier shall comply
with the following requirements with respect to the marketing,
offering and provision of products or services to residential
and small commercial retail customers:
(i) All marketing materials, including, but not
limited to, electronic marketing materials, in-person
solicitations, and telephone solicitations, shall contain
information that adequately discloses the prices, terms,

HB3779 - 587 - LRB104 11172 AAS 21254 b
and conditions of the products or services that the
alternative retail electric supplier is offering or
selling to the customer and shall disclose the current
utility electric supply price to compare applicable at the
time the alternative retail electric supplier is offering
or selling the products or services to the customer and
shall disclose the date on which the utility electric
supply price to compare became effective and the date on
which it will expire. The utility electric supply price to
compare shall be the sum of the electric supply charge and
the transmission services charge and shall not include the
purchased electricity adjustment. The disclosure shall
include a statement that the price to compare does not
include the purchased electricity adjustment, and, if
applicable, the range of the purchased electricity
adjustment. All marketing materials, including, but not
limited to, electronic marketing materials, in-person
solicitations, and telephone solicitations, shall include
the following statement:
"(Name of the alternative retail electric
supplier) is not the same entity as your electric
delivery company. You are not required to enroll with
(name of alternative retail electric supplier).
Beginning on (effective date), the electric supply
price to compare is (price in cents per kilowatt
hour). The electric utility electric supply price will

HB3779 - 588 - LRB104 11172 AAS 21254 b
expire on (expiration date). The utility electric
supply price to compare does not include the purchased
electricity adjustment factor. For more information go
to the Illinois Commerce Commission's free website at
www.pluginillinois.org.".
If applicable, the statement shall also include the
following statement:
"The purchased electricity adjustment factor may
range between +.5 cents and -.5 cents per kilowatt
hour.".
This paragraph (i) does not apply to goodwill or
institutional advertising.
(ii) Before any customer is switched from another
supplier, the alternative retail electric supplier shall
give the customer written information that adequately
discloses, in plain language, the prices, terms and
conditions of the products and services being offered and
sold to the customer. This written information shall be
provided in a language in which the customer subject to
the marketing or solicitation is able to understand and
communicate, and the alternative retail electric supplier
shall not switch a customer who is unable to understand
and communicate in a language in which the marketing or
solicitation was conducted. The alternative retail
electric supplier shall comply with Section 2N of the
Consumer Fraud and Deceptive Business Practices Act.

HB3779 - 589 - LRB104 11172 AAS 21254 b
(iii) An alternative retail electric supplier shall
provide documentation to the Commission and to customers
that substantiates any claims made by the alternative
retail electric supplier regarding the technologies and
fuel types used to generate the electricity offered or
sold to customers.
(iv) The alternative retail electric supplier shall
provide to the customer (1) itemized billing statements
that describe the products and services provided to the
customer and their prices, and (2) an additional
statement, at least annually, that adequately discloses
the average monthly prices, and the terms and conditions,
of the products and services sold to the customer.
(v) All in-person and telephone solicitations shall be
conducted in, translated into, and provided in a language
in which the consumer subject to the marketing or
solicitation is able to understand and communicate. An
alternative retail electric supplier shall terminate a
solicitation if the consumer subject to the marketing or
communication is unable to understand and communicate in
the language in which the marketing or solicitation is
being conducted. An alternative retail electric supplier
shall comply with Section 2N of the Consumer Fraud and
Deceptive Business Practices Act.
(vi) Each alternative retail electric supplier shall
conduct training for individual representatives engaged in

HB3779 - 590 - LRB104 11172 AAS 21254 b
in-person solicitation and telemarketing to residential
customers on behalf of that alternative retail electric
supplier prior to conducting any such solicitations on the
alternative retail electric supplier's behalf. Each
alternative retail electric supplier shall submit a copy
of its training material to the Commission on an annual
basis and the Commission shall have the right to review
and require updates to the material. After initial
training, each alternative retail electric supplier shall
be required to conduct refresher training for its
individual representatives every 6 months.
(f) An alternative retail electric supplier may limit the
overall size or availability of a service offering by
specifying one or more of the following: a maximum number of
customers, maximum amount of electric load to be served, time
period during which the offering will be available, or other
comparable limitation, but not including the geographic
locations of customers within the area which the alternative
retail electric supplier is certificated to serve. The
alternative retail electric supplier shall file the terms and
conditions of such service offering including the applicable
limitations with the Commission prior to making the service
offering available to customers.
(g) Nothing in this Section shall be construed as
preventing an alternative retail electric supplier, which is
an affiliate of, or which contracts with, (i) an industry or

HB3779 - 591 - LRB104 11172 AAS 21254 b
trade organization or association, (ii) a membership
organization or association that exists for a purpose other
than the purchase of electricity, or (iii) another
organization that meets criteria established in a rule adopted
by the Commission, from offering through the organization or
association services at prices, terms and conditions that are
available solely to the members of the organization or
association.
(h) For all potentially eligible retail customers, as
defined in Section 16-111.5, served by an alternative retail
electric supplier, or electric utility other than the electric
utility in whose service area a customer is located, such
supplier or utility shall purchase products that include the
same percentage of renewable energy resources, as defined in
Section 1-10 of the Illinois Power Agency Act, as was procured
for the utility in whose service area such customers are
located for the immediately prior delivery year. Such clean
energy shall include all environmental attributes as described
in Section 16-111.5 and match the eligibility criteria of
resources eligible for the renewable portfolio standard
described in subsections (c)(I) and (c)(J) of Section 1-75 of
the Illinois Power Agency Act.
(Source: P.A. 102-459, eff. 8-20-21; 103-237, eff. 6-30-23.)
(220 ILCS 5/16-115D)
Sec. 16-115D. Renewable portfolio standard for alternative

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retail electric suppliers and electric utilities operating
outside their service territories.
(a) An alternative retail electric supplier shall be
responsible for procuring cost-effective renewable energy
resources as required under item (5) of subsection (d) of
Section 16-115 of this Act as outlined herein:
(1) The definition of renewable energy resources
contained in Section 1-10 of the Illinois Power Agency Act
applies to all renewable energy resources required to be
procured by alternative retail electric suppliers.
(2) Through May 31, 2017, the quantity of renewable
energy resources shall be measured as a percentage of the
actual amount of metered electricity (megawatt-hours)
delivered by the alternative retail electric supplier to
Illinois retail customers during the 12-month period June
1 through May 31, commencing June 1, 2009, and the
comparable 12-month period in each year thereafter except
as provided in item (6) of this subsection (a).
(3) Through May 31, 2017, the quantity of renewable
energy resources shall be in amounts at least equal to the
annual percentages set forth in item (1) of subsection (c)
of Section 1-75 of the Illinois Power Agency Act. At least
60% of the renewable energy resources procured pursuant to
items (1) and (3) of subsection (b) of this Section shall
come from wind generation and, starting June 1, 2015, at
least 6% of the renewable energy resources procured

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pursuant to items (1) and (3) of subsection (b) of this
Section shall come from solar photovoltaics. If, in any
given year, an alternative retail electric supplier does
not purchase at least these levels of renewable energy
resources, then the alternative retail electric supplier
shall make alternative compliance payments, as described
in subsection (d) of this Section.
(3.5) For the delivery year commencing June 1, 2017,
the quantity of renewable energy resources shall be at
least 13.0% of the uncovered amount of metered electricity
(megawatt-hours) delivered by the alternative retail
electric supplier to Illinois retail customers during the
delivery year, which uncovered amount shall equal 50% of
such metered electricity delivered by the alternative
retail electric supplier. For the delivery year commencing
June 1, 2018, the quantity of renewable energy resources
shall be at least 14.5% of the uncovered amount of metered
electricity (megawatt-hours) delivered by the alternative
retail electric supplier to Illinois retail customers
during the delivery year, which uncovered amount shall
equal 25% of such metered electricity delivered by the
alternative retail electric supplier. At least 32% of the
renewable energy resources procured by the alternative
retail electric supplier for its uncovered portion under
this paragraph (3.5) shall come from wind or photovoltaic
generation. The renewable energy resources procured under

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this paragraph (3.5) shall not include any resources from
a facility whose costs were being recovered through rates
regulated by any state or states on or after January 1,
2017.
(4) The quantity and source of renewable energy
resources shall be independently verified through the PJM
Environmental Information System Generation Attribute
Tracking System (PJM-GATS) or the Midwest Renewable Energy
Tracking System (M-RETS), which shall document the
location of generation, resource type, month, and year of
generation for all qualifying renewable energy resources
that an alternative retail electric supplier uses to
comply with this Section. No later than June 1, 2009, the
Illinois Power Agency shall provide PJM-GATS, M-RETS, and
alternative retail electric suppliers with all information
necessary to identify resources located in Illinois,
within states that adjoin Illinois or within portions of
the PJM and MISO footprint in the United States that
qualify under the definition of renewable energy resources
in Section 1-10 of the Illinois Power Agency Act for
compliance with this Section 16-115D. Alternative retail
electric suppliers shall not be subject to the
requirements in item (3) of subsection (c) of Section 1-75
of the Illinois Power Agency Act.
(5) All renewable energy credits used to comply with
this Section shall be permanently retired.

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(6) The required procurement of renewable energy
resources by an alternative retail electric supplier shall
apply to all metered electricity delivered to Illinois
retail customers by the alternative retail electric
supplier pursuant to contracts executed or extended after
March 15, 2009.
(b) Compliance obligations.
(1) Through May 31, 2017, an alternative retail
electric supplier shall comply with the renewable energy
portfolio standards by making an alternative compliance
payment, as described in subsection (d) of this Section,
to cover at least one-half of the alternative retail
electric supplier's compliance obligation for the period
prior to June 1, 2017.
(2) For the delivery years beginning June 1, 2017 and
June 1, 2018, an alternative retail electric supplier need
not make any alternative compliance payment to meet any
portion of its compliance obligation, as set forth in
paragraph (3.5) of subsection (a) of this Section.
(3) An alternative retail electric supplier shall use
any one or combination of the following means to cover the
remainder of the alternative retail electric supplier's
compliance obligation, as set forth in paragraphs (3) and
(3.5) of subsection (a) of this Section, not covered by an
alternative compliance payment made under paragraphs (1)
and (2) of this subsection (b) of this Section:

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(A) Generating electricity using renewable energy
resources identified pursuant to item (4) of
subsection (a) of this Section.
(B) Purchasing electricity generated using
renewable energy resources identified pursuant to item
(4) of subsection (a) of this Section through an
energy contract.
(C) Purchasing renewable energy credits from
renewable energy resources identified pursuant to item
(4) of subsection (a) of this Section.
(D) Making an alternative compliance payment as
described in subsection (d) of this Section.
(c) Use of renewable energy credits.
(1) Renewable energy credits that are not used by an
alternative retail electric supplier to comply with a
renewable portfolio standard in a compliance year may be
banked and carried forward up to 2 12-month compliance
periods after the compliance period in which the credit
was generated for the purpose of complying with a
renewable portfolio standard in those 2 subsequent
compliance periods. For the 2009-2010 and 2010-2011
compliance periods, an alternative retail electric
supplier may use renewable credits generated after
December 31, 2008 and before June 1, 2009 to comply with
this Section.
(2) An alternative retail electric supplier is

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responsible for demonstrating that a renewable energy
credit used to comply with a renewable portfolio standard
is derived from a renewable energy resource and that the
alternative retail electric supplier has not used, traded,
sold, or otherwise transferred the credit.
(3) The same renewable energy credit may be used by an
alternative retail electric supplier to comply with a
federal renewable portfolio standard and a renewable
portfolio standard established under this Act. An
alternative retail electric supplier that uses a renewable
energy credit to comply with a renewable portfolio
standard imposed by any other state may not use the same
credit to comply with a renewable portfolio standard
established under this Act.
(d) Alternative compliance payments.
(1) The Commission shall establish and post on its
website, within 5 business days after entering an order
approving a procurement plan pursuant to Section 1-75 of
the Illinois Power Agency Act, maximum alternative
compliance payment rates, expressed on a per kilowatt-hour
basis, that will be applicable in the first compliance
period following the plan approval. A separate maximum
alternative compliance payment rate shall be established
for the service territory of each electric utility that is
subject to subsection (c) of Section 1-75 of the Illinois
Power Agency Act. Each maximum alternative compliance

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payment rate shall be equal to the maximum allowable
annual estimated average net increase due to the costs of
the utility's purchase of renewable energy resources
included in the amounts paid by eligible retail customers
in connection with electric service, as described in item
(2) of subsection (c) of Section 1-75 of the Illinois
Power Agency Act for the compliance period, and as
established in the approved procurement plan. Following
each procurement event through which renewable energy
resources are purchased for one or more of these utilities
for the compliance period, the Commission shall establish
and post on its website estimates of the alternative
compliance payment rates, expressed on a per kilowatt-hour
basis, that shall apply for that compliance period.
Posting of the estimates shall occur no later than 10
business days following the procurement event, however,
the Commission shall not be required to establish and post
such estimates more often than once per calendar month. By
July 1 of each year, the Commission shall establish and
post on its website the actual alternative compliance
payment rates for the preceding compliance year. For
compliance years beginning prior to June 1, 2014, each
alternative compliance payment rate shall be equal to the
total amount of dollars that the utility contracted to
spend on renewable resources, excepting the additional
incremental cost attributable to solar resources, for the

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compliance period divided by the forecasted load of
eligible retail customers, at the customers' meters, as
previously established in the Commission-approved
procurement plan for that compliance year. For compliance
years commencing on or after June 1, 2014, each
alternative compliance payment rate shall be equal to the
total amount of dollars that the utility contracted to
spend on all renewable resources for the compliance period
divided by the forecasted load of retail customers for
which the utility is procuring renewable energy resources
in a given delivery year, at the customers' meters, as
previously established in the Commission-approved
procurement plan for that compliance year. The actual
alternative compliance payment rates may not exceed the
maximum alternative compliance payment rates established
for the compliance period. For purposes of this subsection
(d), the term "eligible retail customers" has the same
meaning as found in Section 16-111.5 of this Act.
(2) In any given compliance year, an alternative
retail electric supplier may elect to use alternative
compliance payments to comply with all or a part of the
applicable renewable portfolio standard. In the event that
an alternative retail electric supplier elects to make
alternative compliance payments to comply with all or a
part of the applicable renewable portfolio standard, such
payments shall be made by September 1, 2010 for the period

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of June 1, 2009 to May 1, 2010 and by September 1 of each
year thereafter for the subsequent compliance period, in
the manner and form as determined by the Commission. Any
election by an alternative retail electric supplier to use
alternative compliance payments is subject to review by
the Commission under subsection (e) of this Section.
(3) An alternative retail electric supplier's
alternative compliance payments shall be computed
separately for each electric utility's service territory
within which the alternative retail electric supplier
provided retail service during the compliance period,
provided that the electric utility was subject to
subsection (c) of Section 1-75 of the Illinois Power
Agency Act. For each service territory, the alternative
retail electric supplier's alternative compliance payment
shall be equal to (i) the actual alternative compliance
payment rate established in item (1) of this subsection
(d), multiplied by (ii) the actual amount of metered
electricity delivered by the alternative retail electric
supplier to retail customers for which the supplier has a
compliance obligation within the service territory during
the compliance period, multiplied by (iii) the result of
one minus the ratios of the quantity of renewable energy
resources used by the alternative retail electric supplier
to comply with the requirements of this Section within the
service territory to the product of the percentage of

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renewable energy resources required under item (3) or
(3.5) of subsection (a) of this Section and the actual
amount of metered electricity delivered by the alternative
retail electrical supplier to retail customers for which
the supplier has a compliance obligation within the
service territory during the compliance period.
(4) Through May 31, 2017, all alternative compliance
payments by alternative retail electric suppliers shall be
deposited in the Illinois Power Agency Renewable Energy
Resources Fund and used to purchase renewable energy
credits, in accordance with Section 1-56 of the Illinois
Power Agency Act. Beginning April 1, 2012 and by April 1 of
each year thereafter, the Illinois Power Agency shall
submit an annual report to the General Assembly, the
Commission, and alternative retail electric suppliers that
shall include, but not be limited to:
(A) the total amount of alternative compliance
payments received in aggregate from alternative retail
electric suppliers by planning year for all previous
planning years in which the alternative compliance
payment was in effect;
(B) the amount of those payments utilized to
purchased renewable energy credits itemized by the
date of each procurement in which the payments were
utilized; and
(C) the unused and remaining balance in the Agency

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Renewable Energy Resources Fund attributable to those
payments.
(4.5) Beginning with the delivery year commencing June
1, 2017, all alternative compliance payments by
alternative retail electric suppliers shall be remitted to
the applicable electric utility. To facilitate this
remittance, each electric utility shall file a tariff with
the Commission no later than 30 days following the
effective date of this amendatory Act of the 99th General
Assembly, which the Commission shall approve, after notice
and hearing, no later than 45 days after its filing. The
Illinois Power Agency shall use such payments to increase
the amount of renewable energy resources otherwise to be
procured under subsection (c) of Section 1-75 of the
Illinois Power Agency Act.
(5) The Commission, in consultation with the Illinois
Power Agency, shall establish a process or proceeding to
consider the impact of a federal renewable portfolio
standard, if enacted, on the operation of the alternative
compliance mechanism, which shall include, but not be
limited to, developing, to the extent permitted by the
applicable federal statute, an appropriate methodology to
apportion renewable energy credits retired as a result of
alternative compliance payments made in accordance with
this Section. The Commission shall commence any such
process or proceeding within 35 days after enactment of a

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federal renewable portfolio standard.
(e) Each alternative retail electric supplier shall, by
September 1, 2010 and by September 1 of each year thereafter,
prepare and submit to the Commission a report, in a format to
be specified by the Commission, that provides information
certifying compliance by the alternative retail electric
supplier with this Section, including copies of all PJM-GATS
and M-RETS reports, and documentation relating to banking,
retiring renewable energy credits, and any other information
that the Commission determines necessary to ensure compliance
with this Section.
An alternative retail electric supplier may file
commercially or financially sensitive information or trade
secrets with the Commission as provided under the rules of the
Commission. To be filed confidentially, the information shall
be accompanied by an affidavit that sets forth both the
reasons for the confidentiality and a public synopsis of the
information.
(f) The Commission may initiate a contested case to review
allegations that the alternative retail electric supplier has
violated this Section, including an order issued or rule
promulgated under this Section. In any such proceeding, the
alternative retail electric supplier shall have the burden of
proof. If the Commission finds, after notice and hearing, that
an alternative retail electric supplier has violated this
Section, then the Commission shall issue an order requiring

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the alternative retail electric supplier to:
(1) immediately comply with this Section; and
(2) if the violation involves a failure to procure the
requisite quantity of renewable energy resources or pay
the applicable alternative compliance payment by the
annual deadline, the Commission shall require the
alternative retail electric supplier to double the
applicable alternative compliance payment that would
otherwise be required to bring the alternative retail
electric supplier into compliance with this Section.
If an alternative retail electric supplier fails to comply
with the renewable energy resource portfolio requirement or
capacity portfolio requirement in this Section more than once
in a 5-year period, then the Commission shall revoke the
alternative electric supplier's certificate of service
authority. The Commission shall not accept an application for
a certificate of service authority from an alternative retail
electric supplier that has lost certification under this
subsection (f), or any corporate affiliate thereof, for at
least one year after the date of revocation.
(g) All of the provisions of this Section apply to
electric utilities operating outside their service area except
under item (2) of subsection (a) of this Section the quantity
of renewable energy resources shall be measured as a
percentage of the actual amount of electricity
(megawatt-hours) supplied in the State outside of the

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utility's service territory during the 12-month period June 1
through May 31, commencing June 1, 2009, and the comparable
12-month period in each year thereafter except as provided in
item (6) of subsection (a) of this Section.
If any such utility fails to procure the requisite
quantity of renewable energy resources by the annual deadline,
then the Commission shall require the utility to double the
alternative compliance payment that would otherwise be
required to bring the utility into compliance with this
Section.
If any such utility fails to comply with the renewable
energy resource portfolio requirement in this Section more
than once in a 5-year period, then the Commission shall order
the utility to cease all sales outside of the utility's
service territory for a period of at least one year.
(h) The provisions of this Section and the provisions of
subsection (d) of Section 16-115 of this Act relating to
procurement of renewable energy resources shall not apply to
an alternative retail electric supplier that operates a
combined heat and power system in this State or that has a
corporate affiliate that operates such a combined heat and
power system in this State that supplies electricity primarily
to or for the benefit of: (i) facilities owned by the supplier,
its subsidiary, or other corporate affiliate; (ii) facilities
electrically integrated with the electrical system of
facilities owned by the supplier, its subsidiary, or other

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corporate affiliate; or (iii) facilities that are adjacent to
the site on which the combined heat and power system is
located.
(i) The obligations of alternative retail electric
suppliers and electric utilities operating outside their
service territories to procure renewable energy resources,
make alternative compliance payments, and file annual reports,
and the obligations of the Commission to determine and post
alternative compliance payment rates, shall terminate after
May 31, 2019, provided that alternative retail electric
suppliers and electric utilities operating outside their
service territories shall be obligated to make all alternative
compliance payments that they were obligated to pay for
periods through and including May 31, 2019, but were not paid
as of that date. The Commission shall continue to enforce the
payment of unpaid alternative compliance payments in
accordance with subsections (f) and (g) of this Section. All
alternative compliance payments made after May 31, 2016 shall
be remitted to the applicable electric utility and used to
purchase renewable energy credits, in accordance with Section
1-75 of the Illinois Power Agency Act.
This subsection (i) is intended to accommodate the
transition to the procurement of renewable energy resources
for all retail customers in the amounts specified under
subsection (c) of Section 1-75 of the Illinois Power Agency
Act and Section 16-111.5 of this Act, including but not

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limited to the transition to a single charge applicable to all
retail customers to recover the costs of these resources. Each
alternative retail electric supplier shall certify in its
annual reports filed pursuant to subsection (e) of this
Section after May 31, 2019, that its retail customers are not
paying the costs of alternative compliance payments or
renewable energy resources that the alternative retail
electric supplier is not required to remit or purchase under
this Section. The Commission shall have the authority to
initiate an emergency rulemaking to adopt rules regarding such
certification.
(Source: P.A. 99-906, eff. 6-1-17.)
(220 ILCS 5/17-500)
Sec. 17-500. Jurisdiction. Except as provided in the
Electric Supplier Act, the Illinois Municipal Code, the
Municipal and Cooperative Electric Utility Planning and
Transparency Act, and this Article XVII, the Commission, or
any other agency or subdivision thereof of the State of
Illinois or any private entity shall have no jurisdiction over
any electric cooperative or municipal system regardless of
whether any election or elections as provided for herein have
been made, and all control regarding an electric cooperative
or municipal system shall be vested in the electric
cooperative's board of directors or trustees or the applicable
governing body of the municipal system.

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(Source: P.A. 90-561, eff. 12-16-97.)
(220 ILCS 5/17-900)
Sec. 17-900. Customer self-generation of electricity.
(a) The General Assembly finds and declares that municipal
utility systems and electric cooperatives shall continue to be
governed by their respective governing bodies, but that such
governing bodies should recognize and implement policies to
provide the opportunity for their residential and small
commercial customers who wish to self-generate electricity and
for reasonable credits to customers for excess electricity,
balanced against the rights of the other non-self-generating
customers. This includes creating consistent, fair policies
that are accessible to all customers and transparent, fair
processes for raising and addressing any concerns.
(b) Customers have the right to install renewable
generating facilities to be located on the customer's premises
or customer's side of the billing meter and that are intended
primarily to offset the customer's own electrical requirements
and produce, consume, and store their own renewable energy
without discriminatory repercussions from an electric
cooperative or municipal utility system. This includes a
customer's rights to:
(1) generate, consume, and deliver excess renewable
energy to the distribution grid and reduce his or her use
of electricity obtained from the grid;

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(2) use technology to store energy at his or her
residence;
(3) interconnect his or her electrical system that
generates renewable energy, stores energy, or any
combination thereof, with the electricity meter on the
customer's premises that is provided by an electric
cooperative or municipal utility system:
(A) in a timely manner;
(B) in accordance with requirements established by
the electric cooperative or municipal utility to
ensure the safety of utility workers; and
(C) after providing written notice to the electric
cooperative or municipal utility system providing
service in the service territory, installing a
nomenclature plate on the electrical meter panel and
meeting all applicable State and local safety and
electrical code requirements associated with
installing a parallel distributed generation system;
and
(4) receive fair credit for excess energy delivered to
the distribution grid.
(c) The policies of municipal systems and electric
cooperatives regarding self-generation and credits for excess
electricity may reasonably differ from those required of other
entities by Article XVI of the Public Utilities Act or other
Acts. The credits must recognize the value of self-generation

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to the distribution grid and benefits to other customers.
(d) Within 180 days after this amendatory Act of the 102nd
General Assembly, each electric cooperative and municipal
system shall update its policies for the interconnection and
fair crediting of customer self-generation and storage if
necessary, to comply with the standards of subsection (b) of
this Section. Each electric cooperative and municipal system
shall post its updated policies to a public-facing area of its
website.
(e) An electric cooperative or municipal system customer
who produces, consumes, and stores his or her own renewable
energy shall not face discriminatory rate design, fees or
charges, treatment, or excessive compliance requirements that
would unreasonably affect that customer's right to
self-generate electricity as provided for in this Section.
(f) An electric cooperative or municipal utility system
customer shall have a right to appeal any decision related to
self-generation and storage that violates these rights to
self-generation and non-discrimination pursuant to the
provisions of this Section through a complaint under the
Administrative Review Law or similar legal process.
(Source: P.A. 102-662, eff. 9-15-21.)
Section 120. The Environmental Protection Act is amended
by changing Section 9.15 as follows:

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(415 ILCS 5/9.15)
Sec. 9.15. Greenhouse gases.
(a) An air pollution construction permit shall not be
required due to emissions of greenhouse gases if the
equipment, site, or source is not subject to regulation, as
defined by 40 CFR 52.21, as now or hereafter amended, for
greenhouse gases or is otherwise not addressed in this Section
or by the Board in regulations for greenhouse gases. These
exemptions do not relieve an owner or operator from the
obligation to comply with other applicable rules or
regulations.
(b) An air pollution operating permit shall not be
required due to emissions of greenhouse gases if the
equipment, site, or source is not subject to regulation, as
defined by Section 39.5 of this Act, for greenhouse gases or is
otherwise not addressed in this Section or by the Board in
regulations for greenhouse gases. These exemptions do not
relieve an owner or operator from the obligation to comply
with other applicable rules or regulations.
(c) (Blank).
(d) (Blank).
(e) (Blank).
(f) As used in this Section:
"Carbon dioxide emission" means the plant annual CO2 total
output emission as measured by the United States Environmental
Protection Agency in its Emissions & Generation Resource

HB3779 - 612 - LRB104 11172 AAS 21254 b
Integrated Database (eGrid), or its successor.
"Carbon dioxide equivalent emissions" or "CO2e" means the
sum total of the mass amount of emissions in tons per year,
calculated by multiplying the mass amount of each of the 6
greenhouse gases specified in Section 3.207, in tons per year,
by its associated global warming potential as set forth in 40
CFR 98, subpart A, table A-1 or its successor, and then adding
them all together.
"Cogeneration" or "combined heat and power" refers to any
system that, either simultaneously or sequentially, produces
electricity and useful thermal energy from a single fuel
source.
"Copollutants" refers to the 6 criteria pollutants that
have been identified by the United States Environmental
Protection Agency pursuant to the Clean Air Act.
"Electric generating unit" or "EGU" means a fossil
fuel-fired stationary boiler, combustion turbine, or combined
cycle system that serves a generator that has a nameplate
capacity greater than 25 MWe and produces electricity for
sale.
"Environmental justice community" means the definition of
that term based on existing methodologies and findings, used
and as may be updated by the Illinois Power Agency and its
program administrator in the Illinois Solar for All Program.
"Equity investment eligible community" or "eligible
community" means the geographic areas throughout Illinois that

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would most benefit from equitable investments by the State
designed to combat discrimination and foster sustainable
economic growth. Specifically, eligible community means the
following areas:
(1) areas where residents have been historically
excluded from economic opportunities, including
opportunities in the energy sector, as defined as R3 areas
pursuant to Section 10-40 of the Cannabis Regulation and
Tax Act; and
(2) areas where residents have been historically
subject to disproportionate burdens of pollution,
including pollution from the energy sector, as established
by environmental justice communities as defined by the
Illinois Power Agency pursuant to the Illinois Power
Agency Act, excluding any racial or ethnic indicators.
"Equity investment eligible person" or "eligible person"
means the persons who would most benefit from equitable
investments by the State designed to combat discrimination and
foster sustainable economic growth. Specifically, eligible
person means the following people:
(1) persons whose primary residence is in an equity
investment eligible community;
(2) persons whose primary residence is in a
municipality, or a county with a population under 100,000,
where the closure of an electric generating unit or mine
has been publicly announced or the electric generating

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unit or mine is in the process of closing or closed within
the last 5 years;
(3) persons who are graduates of or currently enrolled
in the foster care system; or
(4) persons who were formerly incarcerated.
"Existing emissions" means:
(1) for CO2e, the total average tons-per-year of CO2e
emitted by the EGU or large GHG-emitting unit either in
the years 2018 through 2020 or, if the unit was not yet in
operation by January 1, 2018, in the first 3 full years of
that unit's operation; and
(2) for any copollutant, the total average
tons-per-year of that copollutant emitted by the EGU or
large GHG-emitting unit either in the years 2018 through
2020 or, if the unit was not yet in operation by January 1,
2018, in the first 3 full years of that unit's operation.
"Green hydrogen" means a power plant technology in which
an EGU creates electric power exclusively from electrolytic
hydrogen, in a manner that produces zero carbon and
copollutant emissions, using hydrogen fuel that is
electrolyzed using a 100% renewable zero carbon emission
energy source.
"Large greenhouse gas-emitting unit" or "large
GHG-emitting unit" means a unit that is an electric generating
unit or other fossil fuel-fired unit that itself has a
nameplate capacity or serves a generator that has a nameplate

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capacity greater than 25 MWe and that produces electricity,
including, but not limited to, coal-fired, coal-derived,
oil-fired, natural gas-fired, and cogeneration units.
"NOx emission rate" means the plant annual NOx total output
emission rate as measured by the United States Environmental
Protection Agency in its Emissions & Generation Resource
Integrated Database (eGrid), or its successor, in the most
recent year for which data is available.
"Public greenhouse gas-emitting units" or "public
GHG-emitting unit" means large greenhouse gas-emitting units,
including EGUs, that are wholly owned, directly or indirectly,
by one or more municipalities, municipal corporations, joint
municipal electric power agencies, electric cooperatives, or
other governmental or nonprofit entities, whether organized
and created under the laws of Illinois or another state.
"SO2 emission rate" means the "plant annual SO2 total
output emission rate" as measured by the United States
Environmental Protection Agency in its Emissions & Generation
Resource Integrated Database (eGrid), or its successor, in the
most recent year for which data is available.
(g) All EGUs and large greenhouse gas-emitting units that
use coal or oil as a fuel and are not public GHG-emitting units
shall permanently reduce all CO2e and copollutant emissions to
zero no later than January 1, 2030.
(h) All EGUs and large greenhouse gas-emitting units that
use coal as a fuel and are public GHG-emitting units shall

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permanently reduce CO2e emissions to zero no later than
December 31, 2045. Any source or plant with such units must
also reduce their CO2e emissions by 45% from existing
emissions by no later than January 1, 2035. If the emissions
reduction requirement is not achieved by December 31, 2035,
the plant shall retire one or more units or otherwise reduce
its CO2e emissions by 45% from existing emissions by June 30,
2038.
(i) All EGUs and large greenhouse gas-emitting units that
use gas as a fuel and are not public GHG-emitting units shall
permanently reduce all CO2e and copollutant emissions to zero,
including through unit retirement or the use of 100% green
hydrogen or other similar technology that is commercially
proven to achieve zero carbon emissions, according to the
following:
(1) No later than January 1, 2030: all EGUs and large
greenhouse gas-emitting units that have a NOx emissions
rate of greater than 0.12 lbs/MWh or a SO2 emission rate of
greater than 0.006 lb/MWh, and are located in or within 3
miles of an environmental justice community designated as
of January 1, 2021 or an equity investment eligible
community.
(2) No later than January 1, 2040: all EGUs and large
greenhouse gas-emitting units that have a NOx emission
rate of greater than 0.12 lbs/MWh or a SO2 emission rate
greater than 0.006 lb/MWh, and are not located in or

HB3779 - 617 - LRB104 11172 AAS 21254 b
within 3 miles of an environmental justice community
designated as of January 1, 2021 or an equity investment
eligible community. After January 1, 2035, each such EGU
and large greenhouse gas-emitting unit shall reduce its
CO2e emissions by at least 50% from its existing emissions
for CO2e, and shall be limited in operation to, on average,
6 hours or less per day, measured over a calendar year, and
shall not run for more than 24 consecutive hours except in
emergency conditions, as designated by a Regional
Transmission Organization or Independent System Operator.
(3) No later than January 1, 2035: all EGUs and large
greenhouse gas-emitting units that began operation prior
to the effective date of this amendatory Act of the 102nd
General Assembly and have a NOx emission rate of less than
or equal to 0.12 lb/MWh and a SO2 emission rate less than
or equal to 0.006 lb/MWh, and are located in or within 3
miles of an environmental justice community designated as
of January 1, 2021 or an equity investment eligible
community. Each such EGU and large greenhouse gas-emitting
unit shall reduce its CO2e emissions by at least 50% from
its existing emissions for CO2e no later than January 1,
2030.
(4) No later than January 1, 2040: All remaining EGUs
and large greenhouse gas-emitting units that have a heat
rate greater than or equal to 7000 BTU/kWh. Each such EGU
and Large greenhouse gas-emitting unit shall reduce its

HB3779 - 618 - LRB104 11172 AAS 21254 b
CO2e emissions by at least 50% from its existing emissions
for CO2e no later than January 1, 2035.
(5) No later than January 1, 2045: all remaining EGUs
and large greenhouse gas-emitting units.
(j) All EGUs and large greenhouse gas-emitting units that
use gas as a fuel and are public GHG-emitting units shall
permanently reduce all CO2e and copollutant emissions to zero,
including through unit retirement or the use of 100% green
hydrogen or other similar technology that is commercially
proven to achieve zero carbon emissions by January 1, 2045.
(k) All EGUs and large greenhouse gas-emitting units that
utilize combined heat and power or cogeneration technology
shall permanently reduce all CO2e and copollutant emissions to
zero, including through unit retirement or the use of 100%
green hydrogen or other similar technology that is
commercially proven to achieve zero carbon emissions by
January 1, 2045.
(k-5) No EGU or large greenhouse gas-emitting unit that
uses gas as a fuel and is not a public GHG-emitting unit may
emit, in any 12-month period, CO2e or copollutants in excess of
that unit's existing emissions for those pollutants.
(l) Notwithstanding subsections (g) through (k-5), large
GHG-emitting units including EGUs may temporarily continue
emitting CO2e and copollutants after any applicable deadline
specified in any of subsections (g) through (k-5) if it has
been determined, as described in paragraphs (1) and (2) of

HB3779 - 619 - LRB104 11172 AAS 21254 b
this subsection, that ongoing operation of the EGU is
necessary to maintain power grid supply and reliability or
ongoing operation of large GHG-emitting unit that is not an
EGU is necessary to serve as an emergency backup to
operations. Up to and including the occurrence of an emission
reduction deadline under subsection (i), all EGUs and large
GHG-emitting units must comply with the following terms:
(1) if an EGU or large GHG-emitting unit that is a
participant in a regional transmission organization
intends to retire, it must submit documentation to the
appropriate regional transmission organization by the
appropriate deadline that meets all applicable regulatory
requirements necessary to obtain approval to permanently
cease operating the large GHG-emitting unit;
(2) if any EGU or large GHG-emitting unit that is a
participant in a regional transmission organization
receives notice that the regional transmission
organization has determined that continued operation of
the unit is required, the unit may continue operating
until the issue identified by the regional transmission
organization is resolved. The owner or operator of the
unit must cooperate with the regional transmission
organization in resolving the issue and must reduce its
emissions to zero, consistent with the requirements under
subsection (g), (h), (i), (j), (k), or (k-5), as
applicable, as soon as practicable when the issue

HB3779 - 620 - LRB104 11172 AAS 21254 b
identified by the regional transmission organization is
resolved; and
(3) any large GHG-emitting unit that is not a
participant in a regional transmission organization shall
be allowed to continue emitting CO2e and copollutants
after the zero-emission date specified in subsection (g),
(h), (i), (j), (k), or (k-5), as applicable, in the
capacity of an emergency backup unit if approved by the
Illinois Commerce Commission.
(m) No variance, adjusted standard, or other regulatory
relief otherwise available in this Act may be granted to the
emissions reduction and elimination obligations in this
Section.
(n) By June 30 of each year, beginning in 2025, the Agency
shall prepare and publish on its website a report setting
forth the actual greenhouse gas emissions from individual
units and the aggregate statewide emissions from all units for
the prior year.
(o) Every 5 years beginning in 2025, the Environmental
Protection Agency, Illinois Power Agency, in coordination with
the and Illinois Commerce Commission and the Environmental
Protection Agency, shall jointly prepare, and release
publicly, a Clean Resource Plan report to the General Assembly
that examines the State's current progress toward its
renewable energy resource development goals, the status of
CO2e and copollutant emissions reductions, the current status

HB3779 - 621 - LRB104 11172 AAS 21254 b
and progress toward developing and implementing green hydrogen
technologies, the current and projected status of electric
resource adequacy and reliability throughout the State for the
period of ten years after the plan beginning 5 years ahead, and
proposed solutions for any findings. The Environmental
Protection Agency, Illinois Power Agency, and Illinois
Commerce Commission shall consult PJM Interconnection, LLC and
Midcontinent Independent System Operator, Inc., or their
respective successor organizations regarding forecasted
resource adequacy and reliability needs, anticipated new
generation interconnection, new transmission development or
upgrades, and any announced large GHG-emitting unit closure
dates and include this information in the report. The Clean
Resource Planreport shall examine multiple scenarios of
resource development that would maintain resource adequacy
over the ten year planning period and must include scenarios
where the requirements for CO2e and copollutant emissions
reductions required under subsection (i) and subsection (k-5)
of this section, as set out in Public Act 102-0662, are
maintained. The multiple scenarios will be used to identify
the least-cost energy resource portfolio that maintains
resource adequacy and reliability while prioritizing the
health and wellbeing of all Illinois residents, particularly
those residing in Environmental Justice Communities as defined
in IPA Act. The Clean Resource Plan must consider changes to
anticipated load growth, including but not limited to, the

HB3779 - 622 - LRB104 11172 AAS 21254 b
electrification of transportation methods and space heating,
and the growth of large industrial energy loads, such as data
centers. The report shall be structured such that all modeled
scenarios avoid resource adequacy shortfalls, including
ensuring that there will be sufficient in-state capacity to
meet the zonal requirements of MISO Local Resource Zone 4 or
the PJM Commonwealth Edison Zone, per the requirements of the
respective regional transmission organizations (or any
successor construct), and that the modeled portfolios meet
reliability standards consistent with best practices in energy
resource planning. The Illinois Power Agency, through its
Office of Energy Modeling referenced in Section 1-79 of the
Illinois Power Agency Act, will take primary responsibility
for the Clean Resource Plan described in this subsection. The
draft resource plan report shall be released publicly by no
later than December 15 of the year it is prepared. The draft
Clean Resource Plan will provide an overview of potential
resource scenarios and propose a scenario that best serves the
people of Illinois by balancing public health and safety,
affordability, reliability, resource adequacy, and commitment
to reducing CO2e emissions. The draft resource plan will
consider and model potential cost savings and reliability
benefits of distributed energy resources, as defined in
Section 16-107.6 of the Public Utilities Act. If the
Environmental Protection Agency, Illinois Power Agency, and
Illinois Commerce Commission jointly conclude in the report

HB3779 - 623 - LRB104 11172 AAS 21254 b
that the data from the regional grid operators, the pace of
renewable energy development, the pace of development of
energy storage and demand response utilization, transmission
capacity, and the CO2e and copollutant emissions reductions
required by subsection (i) or (k-5) reasonably demonstrate
that a resource adequacy shortfall will occur, including
whether there will be sufficient in-state capacity to meet the
zonal requirements of MISO Zone 4 or the PJM ComEd Zone, per
the requirements of the regional transmission organizations,
or that the regional transmission operators determine that a
reliability violation will occur during the time frame the
study is evaluating, then the Illinois Power Agency, in
conjunction with the Environmental Protection Agency shall
develop a plan to reduce or delay CO2e and copollutant
emissions reductions requirements only to the extent and for
the duration necessary to meet the resource adequacy and
reliability needs of the State, including allowing any plants
whose emission reduction deadline has been identified in the
plan as creating a reliability concern to continue operating,
including operating with reduced emissions or as emergency
backup where appropriate. The plan shall also consider the use
of renewable energy, energy storage, demand response,
transmission development, or other strategies to resolve the
identified resource adequacy shortfall or reliability
violation.
(1) In developing the draft resource plan, the

HB3779 - 624 - LRB104 11172 AAS 21254 b
Environmental Protection Agency and the Illinois Power
Agency shall hold at least one workshop open to, and
accessible at a time and place convenient to, the public
and shall consider any comments made by stakeholders or
the public. Upon development of the draft plan, copies of
the plan shall be posted and made publicly available on
the Environmental Protection Agency's, the Illinois Power
Agency's, and the Illinois Commerce Commission's websites.
All interested parties shall have 60 days following the
date of posting to provide comment to the Environmental
Protection Agency and the Illinois Power Agency on the
plan. All comments submitted to the Environmental
Protection Agency and the Illinois Power Agency shall be
encouraged to be specific, supported by data or other
detailed analyses, and, if objecting to all or a portion
of the plan, accompanied by specific alternative wording
or proposals. All comments shall be posted on the
Environmental Protection Agency's, the Illinois Power
Agency's, and the Illinois Commerce Commission's websites.
Within 30 days following the end of the 60-day review
period, the Environmental Protection Agency and the
Illinois Power Agency shall revise the plan as necessary
based on the comments received and file its revised plan
with the Illinois Commerce Commission for approval.
(2) Within 60 days after the filing of the revised
plan at the Illinois Commerce Commission, any person

HB3779 - 625 - LRB104 11172 AAS 21254 b
objecting to the plan shall file an objection with the
Illinois Commerce Commission. Within 30 days after the
expiration of the comment period, the Illinois Commerce
Commission shall determine whether an evidentiary hearing
is necessary. The Illinois Commerce Commission shall also
host 3 public hearings within 90 days after the plan is
filed. Following the evidentiary and public hearings, the
Illinois Commerce Commission shall enter its order
approving or approving with modifications the reliability
mitigation plan within 180 days.
(3) The Illinois Commerce Commission shall only
approve the plan if the Illinois Commerce Commission
determines that it will avoid any and all resolve the
resource adequacy or reliability deficiency identified in
the reliability mitigation plan at the least amount of CO2e
and copollutant emissions, taking into consideration the
emissions impacts on environmental justice communities,
and that it will ensure adequate, reliable, affordable,
efficient, and environmentally sustainable electric
service at the lowest total cost over time, taking into
account the impact of increases in emissions.
(4) If the selected plan and priority resource
scenario requires additional renewable energy or energy
storage resources than those planned to be procured under
the current versions of the Long-Term Renewable Resources
Procurement Plan developed under Section 1-75 of the

HB3779 - 626 - LRB104 11172 AAS 21254 b
Illinois Power Agency Act and Section 16-111.5 of the
Public Utilities Act, and the Energy Storage Procurement
Plan under Section 1-93 of the Illinois Power Agency Act,
then the Illinois Power Agency shall propose new
procurement targets in those plans that follow the
approval of the Clean Resource Plan. The revised plan or
plans shall include the additional funds needed to ensure
these procurements, and the Illinois Commerce Commission
shall approve the additional funds if it finds that the
expected long-term cost savings to eligible retail
customers from the procurements enabled by the additional
funds exceed the additional costs.
(5) If the selected plan and priority resource
scenario includes a plan to reduce or delay CO2e and
copollutant emissions reductions requirements, the
Environmental Protection Agency shall delay emissions
reductions in Section (i) or Section (k-5) of this
Section, as set out in Public Act 102-0662, to the extent
required by the selected plan.
(6) (4) If the plan includes measures to reduce or
delay emission reduction requirements, and if the resource
adequacy or reliability deficiency identified in the
resource reliability mitigation plan is resolved or
reduced, the Environmental Protection Agency and the
Illinois Power Agency shall may file an amended plan
adjusting the reduction or delay in CO2e and copollutant

HB3779 - 627 - LRB104 11172 AAS 21254 b
emission reduction requirements identified in the plan.
(Source: P.A. 102-662, eff. 9-15-21; 102-1031, eff. 5-27-22.)
Section 125. The Illinois Highway Code is amended by
changing Section 9-113 as follows:
(605 ILCS 5/9-113) (from Ch. 121, par. 9-113)
Sec. 9-113. (a) No ditches, drains, track, rails, poles,
wires, pipe line or other equipment of any public utility
company, municipal corporation or other public or private
corporation, association or person shall be located, placed or
constructed upon, under or along any highway, or upon any
township or district road, without first obtaining the written
consent of the appropriate highway authority as hereinafter
provided for in this Section.
(b) The State and county highway authorities are
authorized to promulgate reasonable and necessary rules,
regulations, and specifications for highways for the
administration of this Section. In addition to rules
promulgated under this subsection (b), the State highway
authority shall and a county highway authority may adopt
coordination strategies and practices designed and intended to
establish and implement effective communication respecting
planned highway projects that the State or county highway
authority believes may require removal, relocation, or
modification in accordance with subsection (f) of this

HB3779 - 628 - LRB104 11172 AAS 21254 b
Section. The strategies and practices adopted shall include
but need not be limited to the delivery of 5 year programs,
annual programs, and the establishment of coordination
councils in the locales and with the utility participation
that will best facilitate and accomplish the requirements of
the State and county highway authority acting under subsection
(f) of this Section. The utility participation shall include
assisting the appropriate highway authority in establishing a
schedule for the removal, relocation, or modification of the
owner's facilities in accordance with subsection (f) of this
Section. In addition, each utility shall designate in writing
to the Secretary of Transportation or his or her designee an
agent for notice and the delivery of programs. The
coordination councils must be established on or before January
1, 2002. The 90 day deadline for removal, relocation, or
modification of the ditches, drains, track, rails, poles,
wires, pipe line, or other equipment in subsection (f) of this
Section shall be enforceable upon the establishment of a
coordination council in the district or locale where the
property in question is located. The coordination councils
organized by a county highway authority shall include the
county engineer, the County Board Chairman or his or her
designee, and with such utility participation as will best
facilitate and accomplish the requirements of a highway
authority acting under subsection (f) of this Section. Should
a county highway authority decide not to establish

HB3779 - 629 - LRB104 11172 AAS 21254 b
coordination councils, the 90 day deadline for removal,
relocation, or modification of the ditches, drains, track,
rails, poles, wires, pipe line, or other equipment in
subsection (f) of this Section shall be waived for those
highways.
(c) In the case of non-toll federal-aid fully
access-controlled State highways, the State highway authority
shall not grant consent to the location, placement or
construction of ditches, drains, track, rails, poles, wires,
pipe line or other equipment upon, under or along any such
non-toll federal-aid fully access-controlled State highway,
which:
(1) would require cutting the pavement structure
portion of such highway for installation or, except in the
event of an emergency, would require the use of any part of
such highway right-of-way for purposes of maintenance or
repair. Where, however, the State highway authority
determines prior to installation that there is no other
access available for maintenance or repair purposes, use
by the entity of such highway right-of-way shall be
permitted for such purposes in strict accordance with the
rules, regulations and specifications of the State highway
authority, provided however, that except in the case of
access to bridge structures, in no such case shall an
entity be permitted access from the through-travel lanes,
shoulders or ramps of the non-toll federal-aid fully

HB3779 - 630 - LRB104 11172 AAS 21254 b
access-controlled State highway to maintain or repair its
accommodation; or
(2) would in the judgment of the State highway
authority, endanger or impair any such ditches, drains,
track, rails, poles, wires, pipe lines or other equipment
already in place; or
(3) would, if installed longitudinally within the
access control lines of such highway, be above ground
after installation except if they are approved pursuant to
subsection c-1 that the State highway authority may
consent to any above ground installation upon, under or
along any bridge, interchange or grade separation within
the right-of-way which installation is otherwise in
compliance with this Section and any rules, regulations or
specifications issued hereunder; or
(4) would be inconsistent with Federal law or with
rules, regulations or directives of appropriate Federal
agencies.
(c-1) As used in this subsection, "high voltage
transmission line" means an electric line and associated
facilities having a design voltage of 100,000 or more. High
voltage transmission lines, under the laws of this state or
the ordinance of any city or county may be constructed,
placed, or maintained within the right of way of any highway,
federally aided state highway, controlled access highway,
interstate highway, or roadway, except as deemed necessary by

HB3779 - 631 - LRB104 11172 AAS 21254 b
the Secretary of Transportation to protect public safety or
ensure the proper function of the highway. If the Secretary of
Transportation denies a high voltage electric line co-location
request, the reasons for the denial must be submitted for
review to the chairs and ranking minority members of the
committees with jurisdiction over energy and transportation
and the Chair of the Illinois Commerce Commission within 90
days of the denial.
In the case of co-location of transmission lines with DOT
highway right-of-way, the Secretary of Transportation, or
their designee, shall, upon written request, engage in
coordination activities with a utility or transmission line
developer to review requested highway corridors for possible
permitted locations of transmission lines. A project
coordinator shall be assigned within 30 days of the written
request. As part of this consultation, the Department must
share all known plans with utilities or developers on
potential future projects that could impact the placement of a
high voltage transmission line.
When a permittable route along a highway corridor has been
identified by the Department and the utility or developer, the
Department must engage in consultation with the utility or
developer to develop a constructability report to be utilized
by both parties when colocation projects are being planned and
approved. The report must be approved by both parties prior to
the Department issuing a permit for use of the highway

HB3779 - 632 - LRB104 11172 AAS 21254 b
right-of-way. The constructability report shall be prepared by
the utility or developer in consultation with the Department
and shall include the terms and conditions for building the
co-located project. Included within the report shall be an
agreed upon timeframe for which there will not be any request
by The Department for relocation of the transmission line. If
the Department needs a transmission line in its right-of-way
relocated, it shall give the transmission line owner a 10-year
advance notice.
(d) In the case of accommodations upon, under or along
non-toll federal-aid fully access-controlled State highways
the State highway authority may charge an entity reasonable
compensation for the right of that entity to longitudinally
locate, place or construct ditches, drains, track, rails,
poles, wires, pipe line or other equipment upon, under or
along such highway. Such compensation may include in-kind
compensation.
Where the entity applying for use of a non-toll
federal-aid fully access-controlled State highway right-of-way
is a public utility company, municipal corporation or other
public or private corporation, association or person, such
compensation shall be based upon but shall not exceed a
reasonable estimate by the State highway authority of the fair
market value of an easement or leasehold for such use of the
highway right-of-way. Where the State highway authority
determines that the applied-for use of such highway

HB3779 - 633 - LRB104 11172 AAS 21254 b
right-of-way is for private land uses by an individual and not
for commercial purposes, the State highway authority may
charge a lesser fee than would be charged a public utility
company, municipal corporation or other public or private
corporation or association as compensation for the use of the
non-toll federal-aid fully access-controlled State highway
right-of-way. In no case shall the written consent of the
State highway authority give or be construed to give any
entity any easement, leasehold or other property interest of
any kind in, upon, under, above or along the non-toll
federal-aid fully access-controlled State highway
right-of-way.
Where the compensation from any entity is in whole or in
part a fee, such fee may be reasonably set, at the election of
the State highway authority, in the form of a single lump sum
payment or a schedule of payments. All such fees charged as
compensation may be reviewed and adjusted upward by the State
highway authority once every 5 years provided that any such
adjustment shall be based on changes in the fair market value
of an easement or leasehold for such use of the non-toll
federal-aid fully access-controlled State highway
right-of-way. All such fees received as compensation by the
State highway authority shall be deposited in the Road Fund.
(e) Any entity applying for consent shall submit such
information in such form and detail to the appropriate highway
authority as to allow the authority to evaluate the entity's

HB3779 - 634 - LRB104 11172 AAS 21254 b
application. In the case of accommodations upon, under or
along non-toll federal-aid fully access-controlled State
highways the entity applying for such consent shall reimburse
the State highway authority for all of the authority's
reasonable expenses in evaluating that entity's application,
including but not limited to engineering and legal fees.
(f) Any ditches, drains, track, rails, poles, wires, pipe
line, or other equipment located, placed, or constructed upon,
under, or along a highway with the consent of the State or
county highway authority under this Section shall, upon
written notice by the State or county highway authority be
removed, relocated, or modified by the owner, the owner's
agents, contractors, or employees at no expense to the State
or county highway authority when and as deemed necessary by
the State or county highway authority for highway or highway
safety purposes. The notice shall be properly given after the
completion of engineering plans, the receipt of the necessary
permits issued by the appropriate State and county highway
authority to begin work, and the establishment of sufficient
rights-of-way for a given utility authorized by the State or
county highway authority to remain on the highway right-of-way
such that the unit of local government or other owner of any
facilities receiving notice in accordance with this subsection
(f) can proceed with relocating, replacing, or reconstructing
the ditches, drains, track, rails, poles, wires, pipe line, or
other equipment. If a permit application to relocate on a

HB3779 - 635 - LRB104 11172 AAS 21254 b
public right-of-way is not filed within 15 days of the receipt
of final engineering plans, the notice precondition of a
permit to begin work is waived. However, under no
circumstances shall this notice provision be construed to
require the State or any government department or agency to
purchase additional rights-of-way to accommodate utilities.
If, within 90 days after receipt of such written notice, the
ditches, drains, track, rails, poles, wires, pipe line, or
other equipment have not been removed, relocated, or modified
to the reasonable satisfaction of the State or county highway
authority, or if arrangements are not made satisfactory to the
State or county highway authority for such removal,
relocation, or modification, the State or county highway
authority may remove, relocate, or modify such ditches,
drains, track, rails, poles, wires, pipe line, or other
equipment and bill the owner thereof for the total cost of such
removal, relocation, or modification. The scope of the project
shall be taken into consideration by the State or county
highway authority in determining satisfactory arrangements.
The State or county highway authority shall determine the
terms of payment of those costs provided that all costs billed
by the State or county highway authority shall not be made
payable over more than a 5 year period from the date of
billing. The State and county highway authority shall have the
power to extend the time of payment in cases of demonstrated
financial hardship by a unit of local government or other

HB3779 - 636 - LRB104 11172 AAS 21254 b
public owner of any facilities removed, relocated, or modified
from the highway right-of-way in accordance with this
subsection (f). This paragraph shall not be construed to
prohibit the State or county highway authority from paying any
part of the cost of removal, relocation, or modification where
such payment is otherwise provided for by State or federal
statute or regulation. At any time within 90 days after
written notice was given, the owner of the drains, track,
rails, poles, wires, pipe line, or other equipment may request
the district engineer or, if appropriate, the county engineer
for a waiver of the 90 day deadline. The appropriate district
or county engineer shall make a decision concerning waiver
within 10 days of receipt of the request and may waive the 90
day deadline if he or she makes a written finding as to the
reasons for waiving the deadline. Reasons for waiving the
deadline shall be limited to acts of God, war, the scope of the
project, the State failing to follow the proper notice
procedure, and any other cause beyond reasonable control of
the owner of the facilities. Waiver must not be unreasonably
withheld. If 90 days after written notice was given, the
ditches, drains, track, rails, poles, wires, pipe line, or
other equipment have not been removed, relocated, or modified
to the satisfaction of the State or county highway authority,
no waiver of deadline has been requested or issued by the
appropriate district or county engineer, and no satisfactory
arrangement has been made with the appropriate State or county

HB3779 - 637 - LRB104 11172 AAS 21254 b
highway authority, the State or county highway authority or
the general contractor of the building project may file a
complaint in the circuit court for an emergency order to
direct and compel the owner to remove, relocate, or modify the
drains, track, rails, poles, wires, pipe line, or other
equipment to the satisfaction of the appropriate highway
authority. The complaint for an order shall be brought in the
circuit in which the subject matter of the complaint is
situated or, if the subject matter of the complaint is
situated in more than one circuit, in any one of those
circuits.
(g) It shall be the sole responsibility of the entity,
without expense to the State highway authority, to maintain
and repair its ditches, drains, track, rails, poles, wires,
pipe line or other equipment after it is located, placed or
constructed upon, under or along any State highway and in no
case shall the State highway authority thereafter be liable or
responsible to the entity for any damages or liability of any
kind whatsoever incurred by the entity or to the entity's
ditches, drains, track, rails, poles, wires, pipe line or
other equipment.
(h) Except as provided in subsection (h-1), upon receipt
of an application therefor, consent to so use a highway may be
granted subject to such terms and conditions not inconsistent
with this Code as the highway authority deems for the best
interest of the public. The terms and conditions required by

HB3779 - 638 - LRB104 11172 AAS 21254 b
the appropriate highway authority may include but need not be
limited to participation by the party granted consent in the
strategies and practices adopted under subsection (b) of this
Section. The petitioner shall pay to the owners of property
abutting upon the affected highways established as though by
common law plat all damages the owners may sustain by reason of
such use of the highway, such damages to be ascertained and
paid in the manner provided by law for the exercise of the
right of eminent domain.
(h-1) With regard to any public utility, as defined in
Section 3-105 of the Public Utilities Act, engaged in public
water or public sanitary sewer service that comes under the
jurisdiction of the Illinois Commerce Commission, upon receipt
of an application therefor, consent to so use a highway may be
granted subject to such terms and conditions not inconsistent
with this Code as the highway authority deems for the best
interest of the public. The terms and conditions required by
the appropriate highway authority may include but need not be
limited to participation by the party granted consent in the
strategies and practices adopted under subsection (b) of this
Section. If the highway authority does not have fee ownership
of the property, the petitioner shall pay to the owners of
property located in the highway right-of-way all damages the
owners may sustain by reason of such use of the highway, such
damages to be ascertained and paid in the manner provided by
law for the exercise of the right of eminent domain. The

HB3779 - 639 - LRB104 11172 AAS 21254 b
consent shall not otherwise relieve the entity granted that
consent from obtaining by purchase, condemnation, or otherwise
the necessary approval of any owner of the fee over or under
which the highway or road is located, except to the extent that
no such owner has paid real estate taxes on the property for
the 2 years prior to the grant of the consent. Owners of
property that abuts the right-of-way but who acquired the
property through a conveyance that either expressly excludes
the property subject to the right-of-way or that describes the
property conveyed as ending at the right-of-way or being
bounded by the right-of-way or road shall not be considered
owners of property located in the right-of-way and shall not
be entitled to damages by reason of the use of the highway or
road for utility purposes, except that this provision shall
not relieve the public utility from the obligation to pay for
any physical damage it causes to improvements lawfully located
in the right-of-way. Owners of abutting property whose
descriptions include the right-of-way but are made subject to
the right-of-way shall be entitled to compensation for use of
the right-of-way. If the property subject to the right-of-way
is not owned by the owners of the abutting property (either
because it is expressly excluded from the property conveyed to
an abutting property owner or the property as conveyed ends at
or is bounded by the right-of-way or road), then the
petitioner shall pay any damages, as so calculated, to the
person or persons who have paid real estate taxes for the

HB3779 - 640 - LRB104 11172 AAS 21254 b
property as reflected in the county tax records. If no person
has paid real estate taxes, then the public interest permits
the installation of the facilities without payment of any
damages. This provision of this amendatory Act of the 93rd
General Assembly is intended to clarify, by codification,
existing law and is not intended to change the law.
(i) Such consent shall be granted by the Department in the
case of a State highway; by the county board or its designated
county superintendent of highways in the case of a county
highway; by either the highway commissioner or the county
superintendent of highways in the case of a township or
district road, provided that if consent is granted by the
highway commissioner, the petition shall be filed with the
commissioner at least 30 days prior to the proposed date of the
beginning of construction, and that if written consent is not
given by the commissioner within 30 days after receipt of the
petition, the applicant may make written application to the
county superintendent of highways for consent to the
construction. In the case of township roads, the county
superintendent of highways may either grant consent for the
construction or deny the application. The county
superintendent of highways shall provide written confirmation,
citing the basis of the decision, to both the highway
commissioner and the applicant. This Section does not vitiate,
extend or otherwise affect any consent granted in accordance
with law prior to the effective date of this Code to so use any

HB3779 - 641 - LRB104 11172 AAS 21254 b
highway.
(j) Nothing in this Section shall limit the right of a
highway authority to permit the location, placement or
construction or any ditches, drains, track, rails, poles,
wires, pipe line or other equipment upon, under or along any
highway or road as a part of its highway or road facilities or
which the highway authority determines is necessary to service
facilities required for operating the highway or road,
including rest areas and weigh stations.
(k) Paragraphs (c) and (d) of this Section shall not apply
to any accommodation located, placed or constructed with the
consent of the State highway authority upon, under or along
any non-toll federal-aid fully access-controlled State highway
prior to July 1, 1984, provided that accommodation was
otherwise in compliance with the rules, regulations and
specifications of the State highway authority.
(l) Except as provided in subsection (l-1), the consent to
be granted pursuant to this Section by the appropriate highway
authority shall be effective only to the extent of the
property interest of the State or government unit served by
that highway authority. Such consent shall not be binding on
any owner of the fee over or under which the highway or road is
located and shall not otherwise relieve the entity granted
that consent from obtaining by purchase, condemnation or
otherwise the necessary approval of any owner of the fee over
or under which the highway or road is located. This paragraph

HB3779 - 642 - LRB104 11172 AAS 21254 b
shall not be construed as a limitation on the use for highway
or road purposes of the land or other property interests
acquired by the public for highway or road purposes, including
the space under or above such right-of-way.
(l-1) With regard to any public utility, as defined in
Section 3-105 of the Public Utilities Act, engaged in public
water or public sanitary sewer service that comes under the
jurisdiction of the Illinois Commerce Commission, the consent
to be granted pursuant to this Section by the appropriate
highway authority shall be effective only to the extent of the
property interest of the State or government unit served by
that highway authority. Such consent shall not be binding on
any owner of the fee over or under which the highway or road is
located but shall be binding on any abutting property owner
whose property boundary ends at the right-of-way of the
highway or road. For purposes of the preceding sentence,
property that includes a portion of a highway or road but is
subject to the highway or road shall not be considered to end
at the highway or road. The consent shall not otherwise
relieve the entity granted that consent from obtaining by
purchase, condemnation or otherwise the necessary approval of
any owner of the fee over or under which the highway or road is
located, except to the extent that no such owner has paid real
estate taxes on the property for the 2 years prior to the grant
of the consent. This provision is not intended to absolve a
utility from obtaining consent from a lawful owner of the

HB3779 - 643 - LRB104 11172 AAS 21254 b
roadway or highway property (i.e. a person whose deed of
conveyance lawfully includes the property, whether or not made
subject to the highway or road) but who does not pay taxes by
reason of Division 6 of Article 10 of the Property Tax Code.
This paragraph shall not be construed as a limitation on the
use for highway or road purposes of the land or other property
interests acquired by the public for highway or road purposes,
including the space under or above such right-of-way.
(m) The provisions of this Section apply to all permits
issued by the Department of Transportation and the appropriate
State or county highway authority.
(Source: P.A. 102-449, eff. 1-1-22.)
Section 130. The Eminent Domain Act is amended by changing
Section 5-5-5 as follows:
(735 ILCS 30/5-5-5)
Sec. 5-5-5. Exercise of the power of eminent domain;
public use; blight.
(a) In addition to all other limitations and requirements,
a condemning authority may not take or damage property by the
exercise of the power of eminent domain unless it is for a
public use, as set forth in this Section.
(a-5) Subsections (b), (c), (d), (e), and (f) of this
Section do not apply to the acquisition of property under the
O'Hare Modernization Act. A condemning authority may exercise

HB3779 - 644 - LRB104 11172 AAS 21254 b
the power of eminent domain for the acquisition or damaging of
property under the O'Hare Modernization Act as provided for by
law in effect prior to the effective date of this Act.
(a-10) Subsections (b), (c), (d), (e), and (f) of this
Section do not apply to the acquisition or damaging of
property in furtherance of the goals and objectives of an
existing tax increment allocation redevelopment plan. A
condemning authority may exercise the power of eminent domain
for the acquisition of property in furtherance of an existing
tax increment allocation redevelopment plan as provided for by
law in effect prior to the effective date of this Act.
As used in this subsection, "existing tax increment
allocation redevelopment plan" means a redevelopment plan that
was adopted under the Tax Increment Allocation Redevelopment
Act (Article 11, Division 74.4 of the Illinois Municipal Code)
prior to April 15, 2006 and for which property assembly costs
were, before that date, included as a budget line item in the
plan or described in the narrative portion of the plan as part
of the redevelopment project, but does not include (i) any
additional area added to the redevelopment project area on or
after April 15, 2006, (ii) any subsequent extension of the
completion date of a redevelopment plan beyond the estimated
completion date established in that plan prior to April 15,
2006, (iii) any acquisition of property in a conservation area
for which the condemnation complaint is filed more than 12
years after the effective date of this Act, or (iv) any

HB3779 - 645 - LRB104 11172 AAS 21254 b
acquisition of property in an industrial park conservation
area.
As used in this subsection, "conservation area" and
"industrial park conservation area" have the same meanings as
under Section 11-74.4-3 of the Illinois Municipal Code.
(b) If the exercise of eminent domain authority is to
acquire property for public ownership and control, then the
condemning authority must prove that (i) the acquisition of
the property is necessary for a public purpose and (ii) the
acquired property will be owned and controlled by the
condemning authority or another governmental entity.
(c) Except when the acquisition is governed by subsection
(b) or is primarily for one of the purposes specified in
subsection (d), (e), or (f) and the condemning authority
elects to proceed under one of those subsections, if the
exercise of eminent domain authority is to acquire property
for private ownership or control, or both, then the condemning
authority must prove by clear and convincing evidence that the
acquisition of the property for private ownership or control
is (i) primarily for the benefit, use, or enjoyment of the
public and (ii) necessary for a public purpose.
An acquisition of property primarily for the purpose of
the elimination of blight is rebuttably presumed to be for a
public purpose and primarily for the benefit, use, or
enjoyment of the public under this subsection.
Any challenge to the existence of blighting factors

HB3779 - 646 - LRB104 11172 AAS 21254 b
alleged in a complaint to condemn under this subsection shall
be raised within 6 months of the filing date of the complaint
to condemn, and if not raised within that time the right to
challenge the existence of those blighting factors shall be
deemed waived.
Evidence that the Illinois Commerce Commission has granted
a certificate or otherwise made a finding of public
convenience and necessity for an acquisition of property (or
any right or interest in property) for private ownership or
control (including, without limitation, an acquisition for
which the use of eminent domain is authorized under the Public
Utilities Act, the Telephone Company Act, or the Electric
Supplier Act) to be used for utility purposes creates a
rebuttable presumption that such acquisition of that property
(or right or interest in property) is (i) primarily for the
benefit, use, or enjoyment of the public and (ii) necessary
for a public purpose.
In the case of an acquisition of property (or any right or
interest in property) for private ownership or control to be
used for utility, pipeline, or railroad purposes for which no
certificate or finding of public convenience and necessity by
the Illinois Commerce Commission is required, evidence that
the acquisition is one for which the use of eminent domain is
authorized under one of the following laws creates a
rebuttable presumption that the acquisition of that property
(or right or interest in property) is (i) primarily for the

HB3779 - 647 - LRB104 11172 AAS 21254 b
benefit, use, or enjoyment of the public and (ii) necessary
for a public purpose:
(1) the Public Utilities Act,
(2) the Telephone Company Act,
(3) the Electric Supplier Act,
(4) the Railroad Terminal Authority Act,
(5) the Grand Avenue Railroad Relocation Authority
Act,
(6) the West Cook Railroad Relocation and Development
Authority Act,
(7) Section 4-505 of the Illinois Highway Code,
(8) Section 17 or 18 of the Railroad Incorporation
Act,
(9) Section 18c-7501 of the Illinois Vehicle Code.
(d) If the exercise of eminent domain authority is to
acquire property for private ownership or control and if the
primary basis for the acquisition is the elimination of blight
and the condemning authority elects to proceed under this
subsection, then the condemning authority must: (i) prove by a
preponderance of the evidence that acquisition of the property
for private ownership or control is necessary for a public
purpose; (ii) prove by a preponderance of the evidence that
the property to be acquired is located in an area that is
currently designated as a blighted area or conservation area
under an applicable statute; (iii) if the existence of blight
or blighting factors is challenged in an appropriate motion

HB3779 - 648 - LRB104 11172 AAS 21254 b
filed within 6 months after the date of filing of the complaint
to condemn, prove by a preponderance of the evidence that the
required blighting factors existed in the area so designated
(but not necessarily in the particular property to be
acquired) at the time of the designation under item (ii) or at
any time thereafter; and (iv) prove by a preponderance of the
evidence at least one of the following:
(A) that it has entered into an express written
agreement in which a private person or entity agrees to
undertake a development project within the blighted area
that specifically details the reasons for which the
property or rights in that property are necessary for the
development project;
(B) that the exercise of eminent domain power and the
proposed use of the property by the condemning authority
are consistent with a regional plan that has been adopted
within the past 5 years in accordance with Section 5-14001
of the Counties Code or Section 11-12-6 of the Illinois
Municipal Code or with a local land resource management
plan adopted under Section 4 of the Local Land Resource
Management Planning Act; or
(C) that (1) the acquired property will be used in the
development of a project that is consistent with the land
uses set forth in a comprehensive redevelopment plan
prepared in accordance with the applicable statute
authorizing the condemning authority to exercise the power

HB3779 - 649 - LRB104 11172 AAS 21254 b
of eminent domain and is consistent with the goals and
purposes of that comprehensive redevelopment plan, and (2)
an enforceable written agreement, deed restriction, or
similar encumbrance has been or will be executed and
recorded against the acquired property to assure that the
project and the use of the property remain consistent with
those land uses, goals, and purposes for a period of at
least 40 years, which execution and recording shall be
included as a requirement in any final order entered in
the condemnation proceeding.
The existence of an ordinance, resolution, or other
official act designating an area as blighted is not prima
facie evidence of the existence of blight. A finding by the
court in a condemnation proceeding that a property or area has
not been proven to be blighted does not apply to any other case
or undermine the designation of a blighted area or
conservation area or the determination of the existence of
blight for any other purpose or under any other statute,
including without limitation under the Tax Increment
Allocation Redevelopment Act (Article 11, Division 74.4 of the
Illinois Municipal Code).
Any challenge to the existence of blighting factors
alleged in a complaint to condemn under this subsection shall
be raised within 6 months of the filing date of the complaint
to condemn, and if not raised within that time the right to
challenge the existence of those blighting factors shall be

HB3779 - 650 - LRB104 11172 AAS 21254 b
deemed waived.
(e) If the exercise of eminent domain authority is to
acquire property for private ownership or control and if the
primary purpose of the acquisition is one of the purposes
specified in item (iii) of this subsection and the condemning
authority elects to proceed under this subsection, then the
condemning authority must prove by a preponderance of the
evidence that: (i) the acquisition of the property is
necessary for a public purpose; (ii) an enforceable written
agreement, deed restriction, or similar encumbrance has been
or will be executed and recorded against the acquired property
to assure that the project and the use of the property remain
consistent with the applicable purpose specified in item (iii)
of this subsection for a period of at least 40 years, which
execution and recording shall be included as a requirement in
any final order entered in the condemnation proceeding; and
(iii) the acquired property will be one of the following:
(1) included in the project site for a residential
project, or a mixed-use project including residential
units, where not less than 20% of the residential units in
the project are made available, for at least 15 years, by
deed restriction, long-term lease, regulatory agreement,
extended use agreement, or a comparable recorded
encumbrance, to low-income households and very low-income
households, as defined in Section 3 of the Illinois
Affordable Housing Act;

HB3779 - 651 - LRB104 11172 AAS 21254 b
(2) used primarily for public airport, road, parking,
or mass transportation purposes and sold or leased to a
private party in a sale-leaseback, lease-leaseback, or
similar structured financing;
(3) owned or used by a public utility or electric
cooperative for utility purposes;
(4) owned or used by a railroad for passenger or
freight transportation purposes;
(5) sold or leased to a private party that operates a
water supply, waste water, recycling, waste disposal,
waste-to-energy, or similar facility;
(6) sold or leased to a not-for-profit corporation
whose purposes include the preservation of open space, the
operation of park space, and similar public purposes;
(7) used as a library, museum, or related facility, or
as infrastructure related to such a facility;
(8) used by a private party for the operation of a
charter school open to the general public; or
(9) a historic resource, as defined in Section 3 of
the Illinois State Agency Historic Resources Preservation
Act, a landmark designated as such under a local
ordinance, or a contributing structure within a local
landmark district listed on the National Register of
Historic Places, that is being acquired for purposes of
preservation or rehabilitation.
(f) If the exercise of eminent domain authority is to

HB3779 - 652 - LRB104 11172 AAS 21254 b
acquire property for public ownership and private control and
if the primary purpose of the acquisition is one of the
purposes specified in item (iii) of this subsection and the
condemning authority elects to proceed under this subsection,
then the condemning authority must prove by a preponderance of
the evidence that: (i) the acquisition of the property is
necessary for a public purpose; (ii) the acquired property
will be owned by the condemning authority or another
governmental entity; and (iii) the acquired property will be
controlled by a private party that operates a business or
facility related to the condemning authority's operation of a
university, medical district, hospital, exposition or
convention center, mass transportation facility, or airport,
including, but not limited to, a medical clinic, research and
development center, food or commercial concession facility,
social service facility, maintenance or storage facility,
cargo facility, rental car facility, bus facility, taxi
facility, flight kitchen, fixed based operation, parking
facility, refueling facility, water supply facility, and
railroad tracks and stations.
(f-5) For all acquisitions governed by subsection (c)
where the property, or any right or interest in property, is to
be used for utility purposes, and where the condemning
authority is an entity required to submit an integrated
resource plan under the Municipal and Cooperative Electric
Utility Planning and Transparency Act, the rebuttable

HB3779 - 653 - LRB104 11172 AAS 21254 b
presumption described in subsection (c) shall only apply if
the most recent integrated resource plan filed by the
condemning authority identified the facility or articulated a
need for a facility of similar capacity and type to the
facility for which the property or right or interest is
sought.
(g) This Article is a limitation on the exercise of the
power of eminent domain, but is not an independent grant of
authority to exercise the power of eminent domain.
(Source: P.A. 94-1055, eff. 1-1-07.)
Section 999. Effective date. This Act takes effect upon
becoming law.
HB3779 - 654 - LRB104 11172 AAS 21254 b
INDEX
Statutes amended in order of appearance
New Act
5 ILCS 120/2 from Ch. 102, par. 42
20 ILCS 605/605-1075
20 ILCS 3855/1-5
20 ILCS 3855/1-10
20 ILCS 3855/1-20
20 ILCS 3855/1-56
20 ILCS 3855/1-75
20 ILCS 3855/1-79 new
20 ILCS 3855/1-93 new
55 ILCS 5/Div. 5-46
heading new
55 ILCS 5/5-46005 new
55 ILCS 5/5-46010 new
55 ILCS 5/5-46015 new
55 ILCS 5/5-46020 new
55 ILCS 5/5-46025 new
65 ILCS 5/Art. 11 Div.
15.5 heading new
65 ILCS 5/11-15.5-5 new
65 ILCS 5/11-15.5-10 new
65 ILCS 5/11-15.5-15 new
65 ILCS 5/11-15.5-20 new
HB3779 - 655 - LRB104 11172 AAS 21254 b
65 ILCS 5/11-15.25 new
65 ILCS 5/11-119.1-4 from Ch. 24, par. 11-119.1-4
65 ILCS 5/11-119.1-5.5 new
65 ILCS 5/11-119.1-10 from Ch. 24, par. 11-119.1-10
220 ILCS 5/3-105 from Ch. 111 2/3, par. 3-105
220 ILCS 5/8-103B
220 ILCS 5/8-104B new
220 ILCS 5/8-406 from Ch. 111 2/3, par. 8-406
220 ILCS 5/8-406.1
220 ILCS 5/8-512
220 ILCS 5/9-229
220 ILCS 5/16-107.5
220 ILCS 5/16-107.6
220 ILCS 5/16-107.7A new
220 ILCS 5/16-107.8 new
220 ILCS 5/16-107.9 new
220 ILCS 5/16-108
220 ILCS 5/16-108.30
220 ILCS 5/16-111.5
220 ILCS 5/16-115A
220 ILCS 5/16-115D
220 ILCS 5/17-500
220 ILCS 5/17-900
415 ILCS 5/9.15
605 ILCS 5/9-113 from Ch. 121, par. 9-113
735 ILCS 30/5-5-5