Bill Text: IL SB3637 | 2023-2024 | 103rd 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, 2024, 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 2024 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 retail 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 2-0)

Status: (Introduced) 2024-03-18 - Added as Co-Sponsor Sen. Laura M. Murphy [SB3637 Detail]

Download: Illinois-2023-SB3637-Introduced.html

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103RD GENERAL ASSEMBLY State of Illinois 2023 and 2024 SB3637 Introduced 2/9/2024, by Sen. Bill Cunningham SYNOPSIS AS INTRODUCED:
See Index
Creates the Municipal and Cooperative Electric Utility Planning and Transparency Act. Provides that, by November 1, 2024, 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 2024 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
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AN ACT concerning regulation.
Be it enacted by the People of the State of Illinois,
represented in the General Assembly:
Section 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, 2024, 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
2024, 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,
2024 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

SB3637 - 24 - LRB103 38841 CES 68978 b
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) Those meetings or portions of meetings of a
fatality review team or the Illinois Fatality Review Team
Advisory Council during which a review of the death of an
eligible adult in which abuse or neglect is suspected,
alleged, or substantiated is conducted pursuant to Section
15 of the Adult Protective Services Act.
(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

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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
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

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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.
(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

SB3637 - 32 - LRB103 38841 CES 68978 b
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.
7-28-23.)
Section 95. The Illinois Power Agency Act is amended by
changing Sections 1-5 and 1-20 as follows:
(20 ILCS 3855/1-5)
Sec. 1-5. Legislative declarations and findings. The
General Assembly finds and declares:
(1) The health, welfare, and prosperity of all
Illinois residents require the provision of adequate,
reliable, affordable, efficient, and environmentally
sustainable electric service at the lowest total cost over
time, taking into account any benefits of price stability.
(1.5) To provide the highest quality of life for the
residents of Illinois and to provide for a clean and
healthy environment, it is the policy of this State to
rapidly transition to 100% clean energy by 2050.
(2) (Blank).
(3) (Blank).
(4) It is necessary to improve the process of
procuring electricity to serve Illinois residents, to

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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
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

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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
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

SB3637 - 35 - LRB103 38841 CES 68978 b
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.
(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

SB3637 - 36 - LRB103 38841 CES 68978 b
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.
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

SB3637 - 37 - LRB103 38841 CES 68978 b
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
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

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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 3855/1-20)
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

SB3637 - 39 - LRB103 38841 CES 68978 b
electric utilities that (A) on December 31, 2005 served
less than 100,000 customers in Illinois and (B) request a
procurement plan for their Illinois jurisdictional load.
Except as provided in paragraph (1.5) of this subsection
(a), the electricity procurement plans shall be updated on
an annual basis and shall include electricity generated
from renewable resources sufficient to achieve the
standards specified in this Act. Beginning with the
delivery year commencing June 1, 2017, develop procurement
plans to include zero emission credits generated from zero
emission facilities sufficient to achieve the standards
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.

SB3637 - 40 - LRB103 38841 CES 68978 b
(2) Conduct competitive procurement processes to
procure the supply resources identified in the electricity
procurement plan, pursuant to Section 16-111.5 of the
Public Utilities Act, and, for the delivery year
commencing June 1, 2017, conduct procurement processes to
procure zero emission credits from zero emission
facilities, under subsection (d-5) of Section 1-75 of this
Act. For the delivery year commencing June 1, 2022, the
Agency is authorized to conduct procurement processes to
procure carbon mitigation credits from carbon-free energy
resources, under subsection (d-10) of Section 1-75 of this
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

SB3637 - 41 - LRB103 38841 CES 68978 b
with subsection (c-5) of Section 1-75 of this Act.
(2.15) Oversee the procurement by electric utilities
of renewable energy credits from newly modernized or
retooled hydropower dams or dams that have been converted
to support hydropower generation.
(3) Develop electric generation and co-generation
facilities that use indigenous coal or renewable
resources, or both, financed with bonds issued by the
Illinois Finance Authority.
(4) Supply electricity from the Agency's facilities at
cost to one or more of the following: municipal electric
systems, governmental aggregators, or rural electric
cooperatives in Illinois.
(b) Except as otherwise limited by this Act, the Agency
has all of the powers necessary or convenient to carry out the
purposes and provisions of this Act, including without
limitation, each of the following:
(1) To have a corporate seal, and to alter that seal at
pleasure, and to use it by causing it or a facsimile to be
affixed or impressed or reproduced in any other manner.
(2) To use the services of the Illinois Finance
Authority necessary to carry out the Agency's purposes.
(3) To negotiate and enter into loan agreements and
other agreements with the Illinois Finance Authority.
(4) To obtain and employ personnel and hire
consultants that are necessary to fulfill the Agency's

SB3637 - 42 - LRB103 38841 CES 68978 b
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
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

SB3637 - 43 - LRB103 38841 CES 68978 b
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
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.

SB3637 - 44 - LRB103 38841 CES 68978 b
(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
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

SB3637 - 45 - LRB103 38841 CES 68978 b
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
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

SB3637 - 46 - LRB103 38841 CES 68978 b
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
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.)

SB3637 - 47 - LRB103 38841 CES 68978 b
Section 100. The Illinois Municipal Code is amended by
changing Sections 11-119.1-4 and 11-119.1-10 and by adding
Section 11-119.1-5.5 as follows:
(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
to serve on the Board of Directors and act as the
representatives of the municipalities, respectively, in
the exercise of their powers as members;

SB3637 - 48 - LRB103 38841 CES 68978 b
(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
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

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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
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

SB3637 - 50 - LRB103 38841 CES 68978 b
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
any;
(2) the manner and time of calling regular and special
meetings of the Board of Directors;

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(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
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

SB3637 - 52 - LRB103 38841 CES 68978 b
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.
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

SB3637 - 53 - LRB103 38841 CES 68978 b
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
reports.
(a) A municipal power agency shall keep accurate accounts
and records of its assets, liabilities, revenues, and

SB3637 - 54 - LRB103 38841 CES 68978 b
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
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

SB3637 - 55 - LRB103 38841 CES 68978 b
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
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

SB3637 - 56 - LRB103 38841 CES 68978 b
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
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

SB3637 - 57 - LRB103 38841 CES 68978 b
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 105. The Public Utilities Act is amended by
changing Sections 3-105, 8-103B, 16-107.5, 16-111.5, 16-115A,
16-115D, and 17-500 and by adding Section 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
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

SB3637 - 58 - LRB103 38841 CES 68978 b
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
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

SB3637 - 59 - LRB103 38841 CES 68978 b
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
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

SB3637 - 60 - LRB103 38841 CES 68978 b
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
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.

SB3637 - 61 - LRB103 38841 CES 68978 b
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
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

SB3637 - 62 - LRB103 38841 CES 68978 b
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
2025, 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.
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

SB3637 - 63 - LRB103 38841 CES 68978 b
(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;
(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

SB3637 - 64 - LRB103 38841 CES 68978 b
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;
(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

SB3637 - 65 - LRB103 38841 CES 68978 b
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 2025,
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
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;

SB3637 - 66 - LRB103 38841 CES 68978 b
(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
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

SB3637 - 67 - LRB103 38841 CES 68978 b
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
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

SB3637 - 68 - LRB103 38841 CES 68978 b
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
2025, 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,
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):

SB3637 - 69 - LRB103 38841 CES 68978 b
(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. ;
(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;

SB3637 - 70 - LRB103 38841 CES 68978 b
(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.
(b-15) Beginning in 2018, 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

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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;
(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;
(9) 13.6% cumulative persisting annual savings for the
year ending December 31, 2026;

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(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 0.9 0.6 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

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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
0.4 percentage point annual increases in total cumulative
persisting annual savings. The Commission may only establish
goals that represent less than 0.5 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 0.5 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) Beginning in 2026, and in every subsequent year,
each electric utility subject to this Section shall achieve
incremental annual savings equal to 2.25% of the utility's
average annual electricity sales in the second, third, and
fourth years prior to the start of each applicable multi-year
energy efficiency planning period referenced in subsection
(f), with an average savings life of at least 13 years. For the
purposes of this Section, "incremental annual savings" means
the total electric savings from all measures installed in a
calendar year that will be realized within 12 months of each
measure's installation. 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

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efficiency measures with average savings lives of less than 5
years.
(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

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approving with modification the plan, the Commission shall
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

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plans approved under this Section and Section 8-104 of this
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.

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(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). At least 40% of all such costs must be for supporting
installation of electrification measures in low income
housing.
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,
be greater than:
(1) 5% per year for each year from 2022 through 2025;

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(2) 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
multifamily housing, commercial buildings, and industrial
facilities; and the quantity of savings associated with each
measure category in each customer category that are being

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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
consumption.
The utilities shall also implement energy efficiency
measures targeted at low-income households, which, for

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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 $1,000,000 $40,000,000 per
year for electric utilities that serve more than 3,000,000
retail customers in the State and no less than $30,000
$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
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

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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
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.

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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
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

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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
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

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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
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

SB3637 - 85 - LRB103 38841 CES 68978 b
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
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,

SB3637 - 86 - LRB103 38841 CES 68978 b
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
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

SB3637 - 87 - LRB103 38841 CES 68978 b
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
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

SB3637 - 88 - LRB103 38841 CES 68978 b
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) Include a cost of equity, which shall be
calculated as the sum of the 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

SB3637 - 89 - LRB103 38841 CES 68978 b
(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).
(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
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

SB3637 - 90 - LRB103 38841 CES 68978 b
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.
(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

SB3637 - 91 - LRB103 38841 CES 68978 b
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
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.

SB3637 - 92 - LRB103 38841 CES 68978 b
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
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)

SB3637 - 93 - LRB103 38841 CES 68978 b
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
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

SB3637 - 94 - LRB103 38841 CES 68978 b
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
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.

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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).
(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

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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
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

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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
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

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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 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.
Capital investment costs shall be depreciated and recovered
over their useful lives consistent with generally accepted
accounting principles. The weighted average cost of capital

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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
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

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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:
(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

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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
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

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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
reduction as part of its review and approval of the
utility's proposed plan.
(3) No later than March 1, 2025, each electric utility
shall file a 4-year energy efficiency plan commencing on
January 1, 2026 that is designed to achieve the
incremental annual savings as 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

SB3637 - 103 - LRB103 38841 CES 68978 b
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 subsection (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.
(4) No later than March 1, 2029, and every 4 years

SB3637 - 104 - LRB103 38841 CES 68978 b
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 the incremental annual savings as defined by
subsection (b-16) 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 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

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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,
the Commission shall, within 30 days, describe in detail the

SB3637 - 106 - LRB103 38841 CES 68978 b
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
standards and municipal regulations, as potentially

SB3637 - 107 - LRB103 38841 CES 68978 b
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,
2019, electric utilities that serve more than

SB3637 - 108 - LRB103 38841 CES 68978 b
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
the utility's program portfolio and for programs that

SB3637 - 109 - LRB103 38841 CES 68978 b
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
16-111.5 of this Act, and for customers that elect hourly

SB3637 - 110 - LRB103 38841 CES 68978 b
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
that the utility achieved a cumulative persisting

SB3637 - 111 - LRB103 38841 CES 68978 b
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
be made to the calculations described in this item

SB3637 - 112 - LRB103 38841 CES 68978 b
(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 incremental annual savings goal
specified in subsection (b-16) of this Section is

SB3637 - 113 - LRB103 38841 CES 68978 b
unmodified, and if the independent evaluator
determines that the utility achieved lifetime
energy savings that is 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% of such lifetime savings goal. If the utility
achieved more than 66% but less than 100% of such
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 each percent by
which the utility failed to achieve the goal.
(ii) If the incremental annual savings goal

SB3637 - 114 - LRB103 38841 CES 68978 b
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 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 134%
of such lifetime savings goal. If the utility
achieved more than 100% 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
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
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

SB3637 - 115 - LRB103 38841 CES 68978 b
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 incremental annual savings goal
specified in subsection (b-16) of this Section is
reduced pursuant to paragraphs (3) or (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 achieved the modified
goal, up to a maximum of a 200 basis point
reduction. (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 incremental annual savings goal
specified in subsection (b-16) of this Section is
reduced pursuant to paragraphs (3) or (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 134% of
the unmodified lifetime savings goal. If the
utility achieved more than 100% of the modified
goal but less than 134% of the unmodified goal,

SB3637 - 116 - LRB103 38841 CES 68978 b
then the return on equity component shall be
linearly interpolated between 0 increase for just
meeting 100% of the modified goal and a 200 basis
point increase for achieving 134% 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
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:

SB3637 - 117 - LRB103 38841 CES 68978 b
(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
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

SB3637 - 118 - LRB103 38841 CES 68978 b
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
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

SB3637 - 119 - LRB103 38841 CES 68978 b
"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
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).

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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) (Blank). 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, 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
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

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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, 2026 through
December 31, 2029 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 100% of the
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 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) Notwithstanding provisions in subparagraphs
(A) and (B) of paragraph (7) of this subsection, 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) 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
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

SB3637 - 123 - LRB103 38841 CES 68978 b
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%
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

SB3637 - 124 - LRB103 38841 CES 68978 b
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
shall determine the cumulative persisting annual 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

SB3637 - 125 - LRB103 38841 CES 68978 b
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,
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

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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.
(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.

SB3637 - 127 - LRB103 38841 CES 68978 b
(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
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,

SB3637 - 128 - LRB103 38841 CES 68978 b
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
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

SB3637 - 129 - LRB103 38841 CES 68978 b
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
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).

SB3637 - 130 - LRB103 38841 CES 68978 b
(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.
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.

SB3637 - 131 - LRB103 38841 CES 68978 b
(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;
(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

SB3637 - 132 - LRB103 38841 CES 68978 b
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
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

SB3637 - 133 - LRB103 38841 CES 68978 b
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
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,

SB3637 - 134 - LRB103 38841 CES 68978 b
2018,
(2) (blank),
(3) 4% for each of the 4 years beginning January 1,
2022,
(4) 4.25% for the 4 years beginning January 1, 2026,
and
(5) 4.25% plus an increase sufficient to account for
the rate of inflation between January 1, 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. 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, 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,

SB3637 - 135 - LRB103 38841 CES 68978 b
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 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 5/16-107.5)
Sec. 16-107.5. Net electricity metering.
(a) The General Assembly finds and declares that a program

SB3637 - 136 - LRB103 38841 CES 68978 b
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
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,

SB3637 - 137 - LRB103 38841 CES 68978 b
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
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

SB3637 - 138 - LRB103 38841 CES 68978 b
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
the electricity provider's expense, which may be the smart
meter described by subsection (b) of Section 16-108.5 of
this Act.

SB3637 - 139 - LRB103 38841 CES 68978 b
(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
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

SB3637 - 140 - LRB103 38841 CES 68978 b
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
provider shall continue to carry over any excess
kilowatt-hour credits earned and apply those credits to
subsequent billing periods to offset any

SB3637 - 141 - LRB103 38841 CES 68978 b
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
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

SB3637 - 142 - LRB103 38841 CES 68978 b
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
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

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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
in the customer's account shall expire.
(e-5) An electricity provider shall provide electric
service to eligible customers who utilize net metering at

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non-discriminatory rates that are identical, with respect to
rate structure, retail rate components, and any monthly
charges, to the rates that the customer would be charged if not
a net metering customer. An electricity provider shall 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
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:

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(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
kilowatt-hour as the electric service provider would
charge for retail kilowatt-hour sales during that same
time-of-use period.

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(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
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

SB3637 - 147 - LRB103 38841 CES 68978 b
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
through use of advanced inverter functions;
(D) predictability of the queue management process
and enforcement of timelines;

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(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
Interconnection Working Group to focus on specific issues
of importance, as appropriate. The Interconnection Working
Group shall report to the Commission on recommended

SB3637 - 149 - LRB103 38841 CES 68978 b
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
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

SB3637 - 150 - LRB103 38841 CES 68978 b
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
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

SB3637 - 151 - LRB103 38841 CES 68978 b
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
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

SB3637 - 152 - LRB103 38841 CES 68978 b
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
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

SB3637 - 153 - LRB103 38841 CES 68978 b
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
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

SB3637 - 154 - LRB103 38841 CES 68978 b
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
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

SB3637 - 155 - LRB103 38841 CES 68978 b
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
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

SB3637 - 156 - LRB103 38841 CES 68978 b
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
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

SB3637 - 157 - LRB103 38841 CES 68978 b
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.
(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

SB3637 - 158 - LRB103 38841 CES 68978 b
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
customer during the monthly billing period exceeds the
amount of electricity produced by the customer, then
the electricity provider shall charge the customer for

SB3637 - 159 - LRB103 38841 CES 68978 b
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
customers with transmission or capacity charges not
charged on a kilowatt-hour basis, the electricity
provider shall prepare a reasonable approximation of

SB3637 - 160 - LRB103 38841 CES 68978 b
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
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

SB3637 - 161 - LRB103 38841 CES 68978 b
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
metering customer. An electricity provider shall not
charge net metering customers any fee or charge or require
additional equipment, insurance, or any other requirements

SB3637 - 162 - LRB103 38841 CES 68978 b
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
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

SB3637 - 163 - LRB103 38841 CES 68978 b
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
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

SB3637 - 164 - LRB103 38841 CES 68978 b
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.
(Source: P.A. 102-662, eff. 9-15-21.)
(220 ILCS 5/16-107.8 new)

SB3637 - 165 - LRB103 38841 CES 68978 b
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
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 103rd 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

SB3637 - 166 - LRB103 38841 CES 68978 b
the effective date of this amendatory Act of the 103rd 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
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
electric capacity, costs of transmission services, and
charges for network integration transmission service,
transmission enhancement, and locational reliability, as
these terms are defined in the PJM Interconnection LLC

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Open Access Transmission Tariff and manuals on January 1,
2019, within the prices for each time block and seasonal
block in which the associated costs generally are
incurred. If the Open Access Transmission Tariff or
manuals subsequently renames those terms, the services
reflected under those terms shall continue to be included
in the time-of-use rate described in this paragraph.
(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
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.
(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,

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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
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,

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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
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

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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
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 5/16-111.5)
Sec. 16-111.5. Provisions relating to procurement.
(a) An electric utility that on December 31, 2005 served
at least 100,000 customers in Illinois shall procure power and
energy for its eligible retail customers in accordance with
the applicable provisions set forth in Section 1-75 of the
Illinois Power Agency Act and this Section. Beginning with the
delivery year commencing on June 1, 2017, such electric
utility shall also procure zero emission credits from zero
emission facilities in accordance with the applicable

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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
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

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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
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

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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;
(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

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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
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

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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;
(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,

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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
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

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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.
(v) for procurement events beginning after May 31,
2025, consideration of whether products offered 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

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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
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

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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
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

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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
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

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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
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

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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
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

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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
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

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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
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.

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(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
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

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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
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

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Section 1-75 of the Illinois Power Agency Act. However, the
Agency may retain a procurement administrator to assist the
Agency in planning and carrying out the procurement events and
implementing the other requirements specified in such
subsection (c-5) of Section 1-75 of the Illinois Power Agency
Act, with the costs incurred by the Agency for the procurement
administrator to be recovered through fees charged to
applicants for selection to sell and deliver renewable energy
credits to electric utilities pursuant to subsection (c-5) of
Section 1-75 of the Illinois Power Agency Act. The procurement
process set forth in Section 1-75 of the Illinois Power Agency
Act and subsection (e) of this Section shall be administered
by a procurement administrator and monitored by a procurement
monitor.
(1) The procurement administrator shall:
(i) design the final procurement process in
accordance with Section 1-75 of the Illinois Power
Agency Act and subsection (e) of this Section
following Commission approval of the procurement plan;
(ii) develop benchmarks in accordance with
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;

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

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

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

SB3637 - 191 - LRB103 38841 CES 68978 b
to each affected electric utility. An affected utility
shall have 30 days following the date of posting to
provide comment to the Agency on the procurement plan.
Other interested entities also may comment on the
procurement plan. All comments submitted to the Agency
shall be specific, supported by data or other detailed
analyses, and, if objecting to all or a portion of the
procurement plan, accompanied by specific alternative
wording or proposals. All comments shall be posted on the
Agency's and Commission's websites. During this 30-day
comment period, the Agency shall hold at least one public
hearing within each utility's service area for the purpose
of receiving public comment on the procurement plan.
Within 14 days following the end of the 30-day review
period, the Agency shall revise the procurement plan as
necessary based on the comments received and file the
procurement plan with the Commission and post the
procurement plan on the websites.
(3) Within 5 days after the filing of the procurement
plan, any person objecting to the procurement plan shall
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.

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(4) The Commission shall approve the procurement plan,
including expressly the forecast used in the procurement
plan, if the Commission determines that it will ensure
adequate, reliable, affordable, efficient, and
environmentally sustainable electric service at the lowest
total cost over time, taking into account any benefits of
price stability.
(4.5) The Commission shall review the Agency's
recommendations for the selection of applicants to enter
into long-term contracts for the sale and delivery of
renewable energy credits from new renewable energy
facilities to be constructed at or adjacent to the sites
of coal-fueled electric generating facilities in this
State in accordance with the provisions of subsection
(c-5) of Section 1-75 of the Illinois Power Agency Act,
and shall approve the Agency's recommendations if the
Commission determines that the applicants recommended by
the Agency for selection, the proposed new renewable
energy facilities to be constructed, the amounts of
renewable energy credits to be delivered pursuant to the
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

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of bidders. The procurement administrator shall
disseminate information to potential bidders to promote a
procurement event, notify potential bidders that the
procurement administrator may enter into a post-bid price
negotiation with bidders that meet the applicable
benchmarks, provide supply requirements, and otherwise
explain the competitive procurement process. In addition
to such other publication as the procurement administrator
determines is appropriate, this information shall be
posted on the Illinois Power Agency's and the Commission's
websites. The procurement administrator shall also
administer the prequalification process, including
evaluation of credit worthiness, compliance with
procurement rules, and agreement to the standard form
contract developed pursuant to paragraph (2) of this
subsection (e). The procurement administrator shall then
identify and register bidders to participate in the
procurement event.
(2) Standard contract forms and credit terms and
instruments. The procurement administrator, in
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

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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
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

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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
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

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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
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

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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,
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.

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(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
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,

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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
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

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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
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

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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
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,

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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
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,

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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
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

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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).
(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.

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(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
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

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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
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

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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
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

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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
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

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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
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

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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
(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

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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,
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

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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
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

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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.
(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

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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
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

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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
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.

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(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
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

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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
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,

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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
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

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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.
(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

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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:
(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

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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
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

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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
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

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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
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

SB3637 - 224 - LRB103 38841 CES 68978 b
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
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

SB3637 - 225 - LRB103 38841 CES 68978 b
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
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

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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
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

SB3637 - 227 - LRB103 38841 CES 68978 b
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
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,

SB3637 - 228 - LRB103 38841 CES 68978 b
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
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

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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
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

SB3637 - 230 - LRB103 38841 CES 68978 b
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
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

SB3637 - 231 - LRB103 38841 CES 68978 b
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
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

SB3637 - 232 - LRB103 38841 CES 68978 b
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.
(Source: P.A. 90-561, eff. 12-16-97.)
Section 110
. 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.

SB3637 - 233 - LRB103 38841 CES 68978 b
(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
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

SB3637 - 234 - LRB103 38841 CES 68978 b
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
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

SB3637 - 235 - LRB103 38841 CES 68978 b
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
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

SB3637 - 236 - LRB103 38841 CES 68978 b
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
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

SB3637 - 237 - LRB103 38841 CES 68978 b
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
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

SB3637 - 238 - LRB103 38841 CES 68978 b
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
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

SB3637 - 239 - LRB103 38841 CES 68978 b
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
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

SB3637 - 240 - LRB103 38841 CES 68978 b
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;
(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

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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
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

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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
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.)
SB3637 - 243 - LRB103 38841 CES 68978 b
INDEX
Statutes amended in order of appearance