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104TH GENERAL ASSEMBLY
State of Illinois
2025 and 2026
SB3929

Introduced 2/6/2026, by Sen. Patrick J. Joyce

SYNOPSIS AS INTRODUCED:

20 ILCS 3855/1-5
220 ILCS 5/16-108.18
415 ILCS 5/9.15

Amends the Illinois Power Agency Act. Provides that it is the policy
of the State to rapidly transition to 100% clean energy by 2060 (rather
than 2050). Amends the Public Utilities Act. In provisions relating to
performance incentives and metrics for electric utilities designed to
encourage those utilities to support and facilitate the State's clean
energy transition, extends timelines by 10 years from existing statutory
dates to allow for competitive market development and cost declines.
Amends the Environmental Protection Act. Provides that all electricity
generating units and large greenhouse gas-emitting units that use coal or
oil as a fuel and are not public GHG-emitting units shall permanently
reduce all CO2e and co-pollutant emissions to zero no later than January 1,
2040 (rather than 2030). Further provides that All EGUs and large
greenhouse gas-emitting units that use coal as a fuel and are public
GHG-emitting units shall permanently reduce CO2e emissions to zero no
later than December 31, 2055 (rather than 2045). Provides that if the
emissions reduction requirement is not achieved by December 31, 2045
(rather than 2035), the plant shall retire one or more units or otherwise
reduce its CO2e emissions by 45% from existing emissions by June 30, 2048
(rather than 2038). Provides that no later than January 1. 2050 (rather
than 2040) all EGUs and large greenhouse gas-emitting units that have a NOx
emission rate of greater than 0.12 lbs/MWh or a SO2 emission rate greater
than 0.006 lb/MWh, and are not located in or within 3 miles of an
environmental justice community designated as of January 1, 2021 or an
equity investment eligible community shall permanently reduce all CO2e and
co-pollutant emissions to zero, including through unit retirement or the
use of 100% green hydrogen or other similar technology that is
commercially proven to achieve zero carbon emissions.
LRB104 19036 BDA 32481 b

A BILL FOR

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1

AN ACT concerning regulation.

2

Be it enacted by the People of the State of Illinois,
3
represented in the General Assembly:

4

Section 5.
The Illinois Power Agency Act is amended by
5
changing Section 1-5 as follows:

6

(20 ILCS 3855/1-5)
7

Sec. 1-5.
Legislative declarations and findings.
The
8
General Assembly finds and declares:
9

(1) The health, welfare, and prosperity of all
10

Illinois residents require the provision of adequate,
11

reliable, affordable, efficient, and environmentally
12

sustainable electric service at the lowest total cost over
13

time, taking into account any benefits of price stability.
14

(1.5) To provide the highest quality of life for the
15

residents of Illinois and to provide for a clean and
16

healthy environment, it is the policy of this State to
17

rapidly transition to 100% clean energy by
2060

2050
.
18

(2) (Blank).
19

(3) (Blank).
20

(4) It is necessary to improve the process of
21

procuring electricity to serve Illinois residents, to
22

promote investment in energy efficiency and
23

demand-response measures, and to maintain and support

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development of clean coal technologies, generation
2

resources that operate at all hours of the day and under
3

all weather conditions, zero emission facilities, and
4

renewable resources.
5

(5) Procuring a diverse electricity supply portfolio
6

will ensure the lowest total cost over time for adequate,
7

reliable, efficient, and environmentally sustainable
8

electric service.
9

(6) Including renewable resources and zero emission
10

credits from zero emission facilities in that portfolio
11

will reduce long-term direct and indirect costs to
12

consumers by decreasing environmental impacts and by
13

avoiding or delaying the need for new generation,
14

transmission, and distribution infrastructure. Developing
15

new renewable energy resources in Illinois, including
16

brownfield solar projects and community solar projects,
17

will help to diversify Illinois electricity supply, avoid
18

and reduce pollution, reduce peak demand, and enhance
19

public health and well-being of Illinois residents.
20

(7) Developing community solar projects in Illinois
21

will help to expand access to renewable energy resources
22

to more Illinois residents.
23

(8) Developing brownfield solar projects in Illinois
24

will help return blighted or contaminated land to
25

productive use while enhancing public health and the
26

well-being of Illinois residents, including those in

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environmental justice communities.
2

(9) Energy efficiency, demand-response measures, zero
3

emission energy, and renewable energy are resources
4

currently underused in Illinois. These resources should be
5

used, when cost effective, to reduce costs to consumers,
6

improve reliability, and improve environmental quality and
7

public health.
8

(10) The State should encourage the use of advanced
9

clean coal technologies that capture and sequester carbon
10

dioxide emissions to advance environmental protection
11

goals and to demonstrate the viability of coal and
12

coal-derived fuels in a carbon-constrained economy.
13

(10.5) The State should encourage the development of
14

interregional high voltage direct current (HVDC)
15

transmission lines that benefit Illinois. All ratepayers
16

in the State served by the regional transmission
17

organization where the HVDC converter station is
18

interconnected benefit from the long-term price stability
19

and market access provided by interregional HVDC
20

transmission facilities. The benefits to Illinois include:
21

reduction in wholesale power prices; access to lower-cost
22

markets; enabling the integration of additional renewable
23

generating units within the State through near
24

instantaneous dispatchability and the provision of
25

ancillary services; creating good-paying union jobs in
26

Illinois; and, enhancing grid reliability and climate

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resilience via HVDC facilities that are installed
2

underground.
3

(10.6) The health, welfare, and safety of the people
4

of the State are advanced by developing new HVDC
5

transmission lines predominantly along transportation
6

rights-of-way, with an HVDC converter station that is
7

located in the service territory of a public utility as
8

defined in Section 3-105 of the Public Utilities Act
9

serving more than 3,000,000 retail customers, and with a
10

project labor agreement as defined in Section 1-10 of this
11

Act.
12

(11) The General Assembly enacted Public Act 96-0795
13

to reform the State's purchasing processes, recognizing
14

that government procurement is susceptible to abuse if
15

structural and procedural safeguards are not in place to
16

ensure independence, insulation, oversight, and
17

transparency.
18

(12) The principles that underlie the procurement
19

reform legislation apply also in the context of power
20

purchasing.
21

(13) To ensure that the benefits of installing
22

renewable resources are available to all Illinois
23

residents and located across the State, subject to
24

appropriation, it is necessary for the Agency to provide
25

public information and educational resources on how
26

residents can benefit from the expansion of renewable

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energy in Illinois and participate in the Illinois Solar
2

for All Program established in Section 1-56, the
3

Adjustable Block program established in Section 1-75, the
4

job training programs established by paragraph (1) of
5

subsection (a) of Section 16-108.12 of the Public
6

Utilities Act, and the programs and resources established
7

by the Energy Transition Act.
8

The General Assembly therefore finds that it is necessary
9
to create the Illinois Power Agency and that the goals and
10
objectives of that Agency are to accomplish each of the
11
following:
12

(A) Develop electricity procurement plans to ensure
13

adequate, reliable, affordable, efficient, and
14

environmentally sustainable electric service at the lowest
15

total cost over time, taking into account any benefits of
16

price stability, for electric utilities that on December
17

31, 2005 provided electric service to at least 100,000
18

customers in Illinois and for small multi-jurisdictional
19

electric utilities that (i) on December 31, 2005 served
20

less than 100,000 customers in Illinois and (ii) request a
21

procurement plan for their Illinois jurisdictional load.
22

The procurement plan shall be updated on an annual basis
23

and shall include renewable energy resources and,
24

beginning with the delivery year commencing June 1, 2017,
25

zero emission credits from zero emission facilities
26

sufficient to achieve the standards specified in this Act.

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(B) Conduct the competitive procurement processes
2

identified in this Act.
3

(C) Develop electric generation and co-generation
4

facilities that use indigenous coal or renewable
5

resources, or both, financed with bonds issued by the
6

Illinois Finance Authority.
7

(D) Supply electricity from the Agency's facilities at
8

cost to one or more of the following: municipal electric
9

systems, governmental aggregators, or rural electric
10

cooperatives in Illinois.
11

(E) Ensure that the process of power procurement is
12

conducted in an ethical and transparent fashion, immune
13

from improper influence.
14

(F) Continue to review its policies and practices to
15

determine how best to meet its mission of providing the
16

lowest cost power to the greatest number of people, at any
17

given point in time, in accordance with applicable law.
18

(G) Operate in a structurally insulated, independent,
19

and transparent fashion so that nothing impedes the
20

Agency's mission to secure power at the best prices the
21

market will bear, provided that the Agency meets all
22

applicable legal requirements.
23

(H) Implement renewable energy procurement and
24

training programs throughout the State to diversify
25

Illinois electricity supply, improve reliability, avoid
26

and reduce pollution, reduce peak demand, and enhance

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public health and well-being of Illinois residents,
2

including low-income residents.
3
(Source: P.A. 102-662, eff. 9-15-21.)

4

Section 10.
The Public Utilities Act is amended by
5
changing Section 16-108.18 as follows:

6

(220 ILCS 5/16-108.18)
7

Sec. 16-108.18.
Performance-based ratemaking.
8

(a) The General Assembly finds:
9

(1) That improving the alignment of utility customer
10

and company interests is critical to ensuring equity,
11

rapid growth of distributed energy resources, electric
12

vehicles, and other new technologies that substantially
13

change the makeup of the grid and protect Illinois
14

residents and businesses from potential economic and
15

environmental harm from the State's energy systems.
16

(2) There is urgency around addressing increasing
17

threats from climate change and assisting communities that
18

have borne disproportionate impacts from climate change,
19

including air pollution, greenhouse gas emissions, and
20

energy burdens. Addressing this problem requires changes
21

to the business model under which utilities in Illinois
22

have traditionally functioned.
23

(3) Providing targeted incentives to support change
24

through a new performance-based structure to enhance

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ratemaking is intended to enable alignment of utility,
2

customer, community, and environmental goals.
3

(4) Though Illinois has taken some measures to move
4

utilities to performance-based ratemaking through the
5

establishment of performance incentives and a
6

performance-based formula rate under the Energy
7

Infrastructure Modernization Act, these measures have not
8

been sufficiently transformative in urgently moving
9

electric utilities toward the State's ambitious energy
10

policy goals: protecting a healthy environment and
11

climate, improving public health, and creating quality
12

jobs and economic opportunities, including wealth
13

building, especially in economically disadvantaged
14

communities and communities of color.
15

(5) These measures were not developed through a
16

process to understand first what performance measures and
17

penalties would help drive the sought-after behavior by
18

the utilities.
19

(6) While the General Assembly has not made a finding
20

that the spending related to the Energy Infrastructure and
21

Modernization Act and its performance metrics was not
22

reasonable, it is important to address concerns that these
23

measures may have resulted in excess utility spending and
24

guaranteed profits without meaningful improvements in
25

customer experience, rate affordability, or equity.
26

(7) Discussions of performance incentive mechanisms

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must always take into account the affordability of
2

customer rates and bills for all customers, including
3

low-income customers.
4

(8) The General Assembly therefore directs the
5

Illinois Commerce Commission to complete a transition that
6

includes a comprehensive performance-based regulation
7

framework for electric utilities serving more than 500,000
8

customers. The breadth of this framework should revise
9

existing utility regulations to position Illinois electric
10

utilities to effectively and efficiently achieve current
11

and anticipated future energy needs of this State, while
12

ensuring affordability for consumers.
13

(b) As used in this Section:
14

"Commission" means the Illinois Commerce Commission.
15

"Demand response" means measures that decrease peak
16
electricity demand or shift demand from peak to off-peak
17
periods.
18

"Distributed energy resources" or "DER" means a wide range
19
of technologies that are connected to the grid including those
20
that are located on the customer side of the customer's
21
electric meter and can provide value to the distribution
22
system, including, but not limited to, distributed generation,
23
energy storage, electric vehicles, and demand response
24
technologies.
25

"Economically disadvantaged communities" means areas of
26
one or more census tracts where average household income does

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not exceed 80% of area median income.
2

"Environmental justice communities" means the definition
3
of that term as used and as may be updated in the long-term
4
renewable resources procurement plan by the Illinois Power
5
Agency and its Program Administrator in the Illinois Solar for
6
All Program.
7

"Equity investment eligible community" means the
8
geographic areas throughout Illinois which would most benefit
9
from equitable investments by the State designed to combat
10
discrimination. Specifically, the equity investment eligible
11
communities shall be defined as the following areas:
12

(1) R3 Areas as established pursuant to Section 10-40
13

of the Cannabis Regulation and Tax Act, where residents
14

have historically been excluded from economic
15

opportunities, including opportunities in the energy
16

sector; and
17

(2) Environmental justice communities, as defined by
18

the Illinois Power Agency pursuant to the Illinois Power
19

Agency Act, where residents have historically been subject
20

to disproportionate burdens of pollution, including
21

pollution from the energy sector.
22

"Performance incentive mechanism" means an instrument by
23
which utility performance is incentivized, which could include
24
a monetary performance incentive.
25

"Performance metric" means a manner of measurement for a
26
particular utility activity.

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(c) Through coordinated, comprehensive system planning,
2
ratemaking, and performance incentives, the performance-based
3
ratemaking framework should be designed to accomplish the
4
following objectives:
5

(1) maintain and improve service reliability and
6

safety, including and particularly in environmental
7

justice, low-income, and equity investment eligible
8

communities;
9

(2) decarbonize utility systems at a pace that meets
10

or exceeds State climate goals, while also ensuring the
11

affordability of rates for all customers, including
12

low-income customers;
13

(3) direct electric utilities to make cost-effective
14

investments that support achievement of Illinois' clean
15

energy policies, including, at a minimum, investments
16

designed to integrate distributed energy resources, comply
17

with critical infrastructure protection standards, plans,
18

and industry best practices, and support and take
19

advantage of potential benefits from the electric vehicle
20

charging and other electrification, while mitigating the
21

impacts;
22

(4) choose cost-effective assets and services, whether
23

utility-supplied or through third-party contracting,
24

considering both economic and environmental costs and the
25

effects on utility rates, to deliver high-quality service
26

to customers at least cost;

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(5) maintain the affordability of electric delivery
2

services for all customers, including low-income
3

customers;
4

(6) maintain and grow a diverse workforce, diverse
5

supplier procurement base and, for relevant programs,
6

diverse approved-vendor pools, including increased
7

opportunities for minority-owned, female-owned,
8

veteran-owned, and disability-owned business enterprises;
9

(7) improve customer service performance and
10

engagement;
11

(8) address the particular burdens faced by consumers
12

in environmental justice and equity investment eligible
13

communities, including shareholder, consumer, and publicly
14

funded bill payment assistance and credit and collection
15

policies, and ensure equitable disconnections, late fees,
16

or arrearages as a result of utility credit and collection
17

practices, which may include consideration of impact by
18

zip code; and
19

(9) implement or otherwise enhance current supplier
20

diversity programs to increase diverse contractor
21

participation in professional services, subcontracting,
22

and prime contracting opportunities with programs that
23

address barriers to access. Supplier diversity programs
24

shall address specific barriers related to RFP and
25

contract access, access to capital, information technology
26

and
cybersecurity

cyber security
access and costs,

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administrative burdens, and quality control with specific
2

metrics, outcomes, and demographic data reported.
3

(d) Multi-Year Rate Plan.
4

(1) If an electric utility had a performance-based
5

formula rate in effect under Section 16-108.5 as of
6

December 31, 2020, then the utility may file a petition
7

proposing tariffs implementing a 4-year Multi-Year Rate
8

Plan as provided in this Section no later than, January
9

20, 2023, for delivery service rates to be effective for
10

the billing periods January 1, 2024 through December 31,
11

2027. The Commission shall issue an order approving or
12

approving as modified the utility's plan no later than
13

December 20, 2023. The term "Multi-Year Rate Plan" refers
14

to a plan establishing the base rates the utility shall
15

charge for each delivery year of the 4-year period to be
16

covered by the plan, which shall be subject to
17

modification only as expressly allowed in this Section.
18

(2) A utility proposing a Multi-Year Rate Plan shall
19

provide a 4-year investment plan and a description of the
20

utility's major planned investments, including, at a
21

minimum, all investments of $2,000,000 or greater over the
22

plan period for an electric utility that serves more than
23

3,000,000 retail customers in the State or $500,000 for an
24

electric utility that serves less than 3,000,000 retail
25

customers in the State but more than 500,000 retail
26

customers in the State. The 4-year investment plan must be

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consistent with the Multi-Year Integrated Grid Plan
2

described in Section 16-105.17 of this Act. The investment
3

plan shall provide sufficiently detailed information, as
4

required by the Commission, including, at a minimum, a
5

description of each investment, the location of the
6

investment, and an explanation of the need for and benefit
7

of such an investment to the extent known.
8

(3) The Multi-Year Rate Plan shall be implemented
9

through a tariff filed with the Commission consistent with
10

the provisions of this paragraph (3) that shall apply to
11

all delivery service customers. The Commission shall
12

initiate and conduct an investigation of the tariff in a
13

manner consistent with the provisions of this paragraph
14

(3) and the provisions of Article IX of this Act, to the
15

extent they do not conflict with this paragraph (3). The
16

Multi-Year Rate Plan approved by the Commission shall do
17

the following:
18

(A) Provide for the recovery of the utility's
19

forecasted rate base, based on the 4-year investment
20

plan and the utility's Integrated Grid Plan. The
21

forecasted rate base must include the utility's
22

planned capital investments, with rates based on
23

average annual plant investment, and
24

investment-related costs, including income tax
25

impacts, depreciation, and ratemaking adjustments and
26

costs that are prudently incurred and reasonable in

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amount consistent with Commission practice and law.
2

The process used to develop the forecasts must be
3

iterative, rigorous, and lead to forecasts that
4

reasonably represent the utility's investments during
5

the forecasted period and ensure that the investments
6

are projected to be used and useful during the annual
7

investment period and least cost, consistent with the
8

provisions of Articles VIII and IX of this Act.
9

(B) The cost of equity shall be approved by the
10

Commission consistent with Commission practice and
11

law.
12

(C) The revenue requirement shall reflect the
13

utility's actual capital structure for the applicable
14

calendar year. A year-end capital structure that
15

includes a common equity ratio of up to and including
16

50% of the total capital structure shall be deemed
17

prudent and reasonable. A higher common equity ratio
18

must be specifically approved by the Commission.
19

(D) (Blank).
20

(E) Provide for recovery of prudent and reasonable
21

projected operating expenses, giving effect to
22

ratemaking adjustments, consistent with Commission
23

practice and law under Article IX of this Act.
24

Operating expenses for years after the first year of
25

the Multi-Year Rate Plan may be estimated by the use of
26

known and measurable changes, expense reductions

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associated with planned capital investments as
2

appropriate, and reasonable and appropriate
3

escalators, indices, or other metrics.
4

(F) Amortize the amount of unprotected
5

property-related excess accumulated deferred income
6

taxes in rates as of January 1, 2023 over a period
7

ending December 31, 2027, unless otherwise required to
8

amortize the excess deferred income tax pursuant to
9

Section 16-108.21 of this Act.
10

(G) Allow recovery of incentive compensation
11

expense that is based on the achievement of
12

operational metrics, including metrics related to
13

budget controls, outage duration and frequency,
14

safety, customer service, efficiency and productivity,
15

environmental compliance and attainment of
16

affordability and environmental goals, and other goals
17

and metrics approved by the Commission. Incentive
18

compensation expense that is based on net income or an
19

affiliate's earnings per share shall not be
20

recoverable.
21

(H) To the maximum extent practicable, align the
22

4-year investment plan and annual capital budgets with
23

the electric utility's Multi-Year Integrated Grid
24

Plan.
25

(4) The Commission shall establish annual rates for
26

each year of the Multi-Year Rate Plan that accurately

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reflect and are based only upon the utility's reasonable
2

and prudent costs of service over the term of the plan,
3

including the effect of all ratemaking adjustments
4

consistent with Commission practice and law as determined
5

by the Commission, provided that the costs are not being
6

recovered elsewhere in rates. Tariff riders authorized by
7

the Commission may continue outside of a plan authorized
8

under this Section to the extent such costs are not
9

recovered elsewhere in rates. For the first Multi-Year
10

Rate Plan, the burden of proof shall be on the electric
11

utility to establish the prudence of investments and
12

expenditures and to establish that such investments
13

consistent with and reasonably necessary to meet the
14

requirements of the utility's first approved Multi-Year
15

Integrated Grid Plan described in Section 16-105.17 of
16

this Act. For subsequent Multi-Year Rate Plans, the burden
17

of proof shall be on the electric utility to establish the
18

prudence of investments and expenditures and to establish
19

that such investments are consistent with and reasonably
20

necessary to meet the requirements of the utility's most
21

recently approved Multi-Year Integrated Grid Plan
22

described in Section 16-105.17 of this Act. The sole fact
23

that a cost differs from that incurred in a prior period or
24

that an investment is different from that described in the
25

Multi-Year Integrated Grid Plan shall not imply the
26

imprudence or unreasonableness of that cost or investment.

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The sole fact that an investment is the same or similar to
2

that described in the Multi-Year Integrated Grid Plan
3

shall not imply prudence and reasonableness of that
4

investment.
5

(5) To facilitate public transparency, all materials,
6

data, testimony, and schedules shall be provided to the
7

Commission in an editable, machine-readable electronic
8

format including .doc, .docx, .xls, .xlsx, and similar
9

file formats, but not including .pdf or .exif. Should
10

utilities designate any materials confidential, they shall
11

have an affirmative duty to explain why the particular
12

information is marked confidential. In determining
13

prudence and reasonableness of rates, the Commission shall
14

make its determination based upon the record, including
15

each public comment filed or provided orally at open
16

meetings consistent with the Commission's rules and
17

practices.
18

(6) The Commission may, by order, establish terms,
19

conditions, and procedures for submitting and approving a
20

Multi-Year Rate Plan necessary to implement this Section
21

and ensure that rates remain just and reasonable during
22

the course of the plan, including terms and procedures for
23

rate adjustment.
24

(7) An electric utility that files a tariff pursuant
25

to paragraph (3) of this subsection
(d)

(e)
must submit a
26

one-time $300,000 filing fee at the time the Chief Clerk

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of the Commission accepts the filing, which shall be a
2

recoverable expense.
3

(8) An electric utility operating under a Multi-Year
4

Rate Plan shall file a new Multi-Year Rate Plan at least
5

300 days prior to the end of the initial Multi-Year Rate
6

Plan unless it elects to file a general rate case pursuant
7

to paragraph (9), and every 4 years thereafter, with a
8

rate-effective date of the proposed tariffs such that,
9

after the Commission suspension period, the rates would
10

take effect immediately at the close of the final year of
11

the initial Multi-Year Rate Plan. In subsequent Multi-Year
12

Rate Plans, as in the initial plans, utilities and
13

stakeholders may propose additional metrics that achieve
14

the outcomes described in paragraph (2) of subsection (f)
15

of this Section.
16

(9) Election of Rate Case.
17

(A) On or before the date prescribed by
18

subparagraph (B) of
this
paragraph (9)
of this
19

Section
, electric utilities that serve more than
20

500,000 retail customers in the State shall file
21

either a general rate case under Section 9-201 of this
22

Act, or a Multi-Year Rate Plan, as set forth in
23

paragraph (1) of this subsection (d).
24

(B) Electric utilities described in subparagraph
25

(A) of
this
paragraph (9)
of this Section
shall file
26

their initial general rate case or Multi-Year Rate

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Plan, as applicable, with the Commission no later than
2

January 20, 2023.
3

(C) Notwithstanding which rate filing option an
4

electric utility elects to file on the date prescribed
5

by subparagraph (B) of
this
paragraph (9)
of this
6

Section
, the electric utility shall be subject to the
7

Multi-year Integrated Plan filing requirements.
8

(D) Following its initial rate filing pursuant to
9

paragraph (2), an electric utility subject to the
10

requirements of this Section shall thereafter be
11

permitted to elect a different rate filing option
12

consistent with any filing intervals established for a
13

general rate case or Multi-Year Rate Plan, as follows:
14

(i) An electric utility that initially elected
15

to file a Multi-Year Rate Plan and thereafter
16

elects to transition to a general rate case may do
17

so upon completion of the 4-year Multi-Year Rate
18

Plan by filing a general rate case at the same time
19

that the utility would have filed its subsequent
20

Multi-Year Rate Plan, as specified in paragraph
21

(8) of this subsection (d). Notwithstanding this
22

election, the annual adjustment of the final year
23

of the Multi-Year Rate Plan shall proceed as
24

specified in paragraph (6) of subsection (f).
25

(ii) An electric utility that initially
26

elected to a file general rate case and thereafter

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elects to transition to a Multi-Year Rate Plan may
2

do so only at the 4-year filing intervals
3

identified by paragraph (8) of this subsection
4

(d).
5

(10) The Commission shall approve tariffs establishing
6

rate design for all delivery service customers unless the
7

electric utility makes the election specified in Section
8

16-105.5, in which case the rate design shall be subject
9

to the provisions of that Section.
10

(11) The Commission shall establish requirements for
11

annual performance evaluation reports to be submitted
12

annually for performance metrics. Such reports shall
13

include, but not be limited to, a description of the
14

utility's performance under each metric and an
15

identification of any extraordinary events that adversely
16

affected the utility's performance.
17

(12) For the first Multi-Year Rate Plan, the
18

Commission shall consolidate its investigation with the
19

proceeding under Section 16-105.17 to establish the
20

Multi-Year Integrated Grid Plan no later than 45 days
21

after plan filing.
22

(13) Where a rate change under a Multi-Year Rate Plan
23

will result in a rate increase, an electric utility may
24

propose a rate phase-in plan that the Commission shall
25

approve with or without modification or deny in its final
26

order approving the new delivery services rates. A

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proposed rate phase-in plan under this paragraph (13) must
2

allow the new delivery services rates to be implemented in
3

no more than 2 steps, as follows: in the first step, at
4

least 50% of the approved rate increase must be reflected
5

in rates, and, in the second step, 100% of the rate
6

increase must be reflected in rates. The second step's
7

rates must take effect no later than 12 months after the
8

first step's rates were placed into effect. The portion of
9

the approved rate increase not implemented in the first
10

step shall be recorded on the electric utility's books as
11

a regulatory asset, and shall accrue carrying costs to
12

ensure that the utility does not recover more or less than
13

it otherwise would because of the deferral. This portion
14

shall be recovered, with such carrying costs at the
15

weighted average cost of capital, through a surcharge
16

applied to retail customer bills that (i) begins no later
17

than 12 months after the date on which the second step's
18

rates went into effect and (ii) is applied over a period
19

not to exceed 24 months. Nothing in this paragraph is
20

intended to limit the Commission's authority to mitigate
21

the impact of rates caused by rate plans, or any other
22

instance on a revenue-neutral basis; nor shall it mitigate
23

a utility's ability to make proposals to mitigate the
24

impact of rates. When a deferral, or similar method, is
25

used to mitigate the impact of rates, the utility should
26

be allowed to recover carrying costs.

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(14) Notwithstanding the provisions of paragraph (13),
2

the Commission may, on its own initiative, take
3

revenue-neutral measures to relieve the impact of rate
4

increases on customers. Such initiatives may be taken by
5

the Commission in the first Multi-Year Rate Plan,
6

subsequent multi-year plans, or in other instances
7

described in this Act.
8

(15) Whenever during the pendency of a Multi-Year Rate
9

Plan, an electric utility subject to this Section becomes
10

aware that, due to circumstances beyond its control,
11

prudent operating practices will require the utility to
12

make adjustments to the Multi-Year Rate Plan, the electric
13

utility may file a petition with the Commission requesting
14

modification of the approved annual revenue requirements
15

included in the Multi-Year Rate Plan. The electric utility
16

must support its request with evidence demonstrating why a
17

modification is necessary, due to circumstances beyond the
18

utility's control, to follow prudent operating practices
19

and must set forth the changes to each annual revenue
20

requirement to be approved, and the basis for any changes
21

in anticipated operating expenses or capital investment
22

levels. The utility shall affirmatively address the impact
23

of the changes on the Multi-Year Integrated Grid Plan and
24

Multi-Year Rate Plan originally submitted and approved by
25

the Commission. Any interested party may file an objection
26

to the changes proposed, or offer alternatives to the

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utility's proposal, as supported by testimony and
2

evidence. After notice and hearing, the Commission shall
3

issue a final order regarding the electric utility's
4

request no later than 180 days after the filing of the
5

petition.
6

(e) Performance incentive mechanisms.
7

(1) The electric industry is undergoing rapid
8

transformation, including fundamental changes in how
9

electricity is generated, procured, and delivered and how
10

customers are choosing to participate in the supply and
11

delivery of electricity to and from the electric grid.
12

Building upon the State's goals to increase the
13

procurement of electricity from renewable energy
14

resources, including distributed generation and storage
15

devices, the General Assembly finds that electric
16

utilities should make cost-effective investments that
17

support moving forward on Illinois' clean energy policies.
18

It is therefore in the State's interest for the Commission
19

to establish performance incentive mechanisms in order to
20

better tie utility revenues to performance and customer
21

benefits, accelerate progress on Illinois energy and other
22

goals, ensure equity and affordability of rates for all
23

customers, including low-income customers, and hold
24

utilities publicly accountable.
25

(2) The Commission shall approve, based on the
26

substantial evidence proffered in the proceeding initiated

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pursuant to this subsection performance metrics that, to
2

the extent practicable and achievable by the electric
3

utility, encourage cost-effective, equitable utility
4

achievement of the outcomes described in this subsection
5

(e) while ensuring no degradation in the significant
6

performance improvement achieved through previously
7

established performance metrics. For each electric
8

utility, the Commission shall approve metrics designed to
9

achieve incremental improvements over baseline performance
10

values and targets, over a performance period of up to 10
11

years, and no less than 4 years
, with timelines extended
12

by 10 years from existing statutory dates to allow for
13

competitive market development and cost declines
.

14

(A) The Commission shall approve no more than 8
15

metrics, with at least one metric from each of the
16

categories below, for each electric utility, from
17

items (i) through (vi) of this subparagraph (A). Upon
18

a utility request, the Commission may approve the use
19

of a specific, measurable, and achievable tracking
20

metric described in paragraph (3) of this subsection
21

(e) as a performance metric pursuant to paragraph (2)
22

of this subsection (e).
23

(i) Metrics designed to ensure the utility
24

maintains and improves the high standards of both
25

overall and locational reliability and resiliency,
26

and makes improvements in power quality, including

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and particularly in environmental justice and
2

equity investment eligible communities.
3

(ii) Peak load reductions attributable to
4

demand response programs.
5

(iii) Supplier diversity expansion, including
6

diverse contractor participation in professional
7

services, subcontracting, and prime contracting
8

opportunities, development of programs that
9

address the barriers to access, aligning
10

demographics of contractors to the demographics in
11

the utility's service territory, establish
12

long-term mentoring relationships that develop and
13

remove barriers to access for diverse and
14

underserved contractors. The utilities shall
15

provide solutions, resources, and tools to address
16

complex barriers of entry related to costly and
17

time-intensive
cybersecurity

cyber security

18

requirements, increasingly complex information
19

technology requirements, insurance barriers,
20

service provider sign-up process barriers,
21

administrative process barriers, and other
22

barriers that inhibit access to RFPs and
23

contracts. For programs with contracts over
24

$1,000,000, winning bidders must demonstrate a
25

subcontractor development or mentoring
26

relationship with at least one of their diverse

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subcontracting partners for a core component of
2

the scope of the project. The mentoring time and
3

cost shall be taken into account in the creation
4

of RFP and shall include a structured and measured
5

plan by the prime contractor to increase the
6

capabilities of the subcontractor in their
7

proposed scope. The metric shall include reporting
8

on all supplier diversity programs by goals,
9

program results, demographics and geography, with
10

separate reporting by category of minority-owned,
11

female-owned, veteran-owned, and disability-owned
12

business enterprise metrics. The report shall
13

include resources and expenses committed to the
14

programs and conversion rates of new diverse
15

utility contractors.
16

(iv) Achieve affordable customer delivery
17

service costs, with particular emphasis on keeping
18

the bills of lower-income households, households
19

in equity investment eligible communities, and
20

household in environmental justice communities
21

within a manageable portion of their income and
22

adopting credit and collection policies that
23

reduce disconnections for these households
24

specifically and for customers overall to ensure
25

equitable disconnections, late fees, or arrearages
26

as a result of utility credit and collection

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practices, which may include consideration of
2

impact by zip code.
3

(v) Metrics designed around the utility's
4

timeliness to customer requests for
5

interconnection in key milestone areas, such as:
6

initial response, supplemental review, and system
7

feasibility study; improved average service
8

reliability index for those customers that have
9

interconnected a distributed renewable energy
10

generation device to the utility's distribution
11

system and are lawfully taking service under an
12

applicable tariff; offering a variety of
13

affordable rate options, including demand
14

response, time of use rates for delivery and
15

supply, real-time pricing rates for supply;
16

comprehensive and predictable net metering, and
17

maximizing the benefits of grid modernization and
18

clean energy for ratepayers; and improving
19

customer access to utility system information
20

according to consumer demand and interest.
21

(vi) Metrics designed to measure the utility's
22

customer service performance, which may include
23

the average length of time to answer a customer's
24

call by a customer service representative, the
25

abandoned call rate and the relative ranking of
26

the electric utility, by a reputable third-party

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organization, in customer service satisfaction
2

when compared to other similar electric utilities
3

in the Midwest region.
4

(B) Performance metrics shall include a
5

description of the metric, a calculation method, a
6

data collection method, annual performance targets,
7

and any incentives or penalties for the utility's
8

achievement of, or failure to achieve, their
9

performance targets, provided that the total amount of
10

potential incentives and penalties shall be
11

symmetrical. Incentives shall be rewards or penalties
12

or both, reflected as basis points added to, or
13

subtracted from, the utility's cost of equity. The
14

metrics and incentives shall apply for the entire time
15

period covered by a Multi-Year Rate Plan. The total
16

for all metrics shall be equal to 40 basis points,
17

however, the Commission may adjust the basis points
18

upward or downward by up to 20 basis points for any
19

given Multi-Year Rate Plan, as appropriate, but in no
20

event may the total exceed 60 basis points or fall
21

below 20 basis points.
22

(C) Metrics related to reliability shall be
23

implemented to ensure equitable benefits to
24

environmental justice and equity investment eligible
25

communities, as defined in this Act.
26

(D) The Commission shall approve performance

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metrics that are reasonably within control of the
2

utility to achieve. The Commission also shall not
3

approve a metric that is solely expected to have the
4

effect of reducing the workforce. Performance metrics
5

should measure outcomes and actual, rather than
6

projected, results where possible. Nothing in this
7

subparagraph is intended to require that different
8

electric utilities must be subject to the same
9

metrics, goals, or incentives.
10

(E) Increases or enhancements to an existing
11

performance goal or target shall be considered in
12

light of other metrics, cost-effectiveness, and other
13

factors the Commission deems appropriate. Performance
14

metrics shall include one year of tracking data
15

collected in a consistent manner, verifiable by an
16

independent evaluator in order to establish a baseline
17

and measure outcomes and actual results against
18

projections where possible.
19

(F) For the purpose of determining reasonable
20

performance metrics and related incentives, the
21

Commission shall develop a methodology to calculate
22

net benefits that includes customer and societal costs
23

and benefits and quantifies the effect on delivery
24

rates. In determining the appropriate level of a
25

performance incentive, the Commission shall consider:
26

the extent to which the amount is likely to encourage

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the utility to achieve the performance target in the
2

least cost manner; the value of benefits to customers,
3

the grid, public health and safety, and the
4

environment from achievement of the performance
5

target, including in particular benefits to equity
6

investment eligible community; the affordability of
7

customer's electric bills, including low-income
8

customers, the utility's revenue requirement, the
9

promotion of renewable and distributed energy, and
10

other such factors that the Commission deems
11

appropriate. The consideration of these factors shall
12

result in an incentive level that ensures benefits
13

exceed costs for customers.
14

(G) Achievement of performance metrics are based
15

on the assumptions that the utility will adopt or
16

implement the technology and equipment, and make the
17

investments to the extent reasonably necessary to
18

achieve the goal. If the electric utility is unable to
19

meet the performance metrics as a result of
20

extraordinary circumstances outside of its control,
21

including, but not limited to, government-declared
22

emergencies, then the utility shall be permitted to
23

file a petition with the Commission requesting that
24

the utility be excused from compliance with the
25

applicable performance goal or goals and the
26

associated financial incentives and penalties. The

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burden of proof shall be on the utility, consistent
2

with Article IX, and the utility's petition shall be
3

supported by substantial evidence. The Commission
4

shall, after notice and hearing, enter its order
5

approving or denying, in whole or in part, the
6

utility's petition based on the extent to which the
7

utility demonstrated that its achievement of the
8

affected metrics and performance goals was hindered by
9

extraordinary circumstances outside of the utility's
10

control.
11

(3) The Commission shall approve reasonable and
12

appropriate tracking metrics to collect and monitor data
13

for the purpose of measuring and reporting utility
14

performance and for establishing future performance
15

metrics. These additional tracking metrics shall include
16

at least one metric from each of the following categories
17

of performance:
18

(A) Minimize emissions of greenhouse gases and
19

other air pollutants that harm human health,
20

particularly in environmental justice and equity
21

investment eligible communities, through minimizing
22

total emissions by accelerating electrification of
23

transportation, buildings, and industries where such
24

electrification results in net reductions, across all
25

fuels and over the life of electrification measures,
26

of greenhouse gases and other pollutants, taking into

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consideration the fuel mix used to produce electricity
2

at the relevant hour and the effect of accelerating
3

electrification on electricity delivery services
4

rates, supply prices, and peak demand, provided the
5

revenues the utility receives from accelerating
6

electrification of transportation, buildings, and
7

industries exceed the costs
, with timelines extended
8

by 10 years from existing statutory dates to allow for
9

competitive market development and cost declines
.
10

(B) Enhance the grid's flexibility to adapt to
11

increased deployment of nondispatchable resources,
12

improve the ability and performance of the grid on
13

load balancing, and offer a variety of rate plans to
14

match consumer consumption patterns and lower consumer
15

bills for electricity delivery and supply.
16

(C) Ensure rates reflect cost savings attributable
17

to grid modernization and utilize distributed energy
18

resources that allow the utility to defer or forgo
19

traditional grid investments that would otherwise be
20

required to provide safe and reliable service.
21

(D) Metrics designed to create and sustain
22

full-time-equivalent jobs and opportunities for all
23

segments of the population and workforce, including
24

minority-owned businesses, women-owned businesses,
25

veteran-owned businesses, and businesses owned by a
26

person or persons with a disability, and that do not,

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consistent with State and federal law, discriminate
2

based on race or socioeconomic status as a result of
3

Public Act 102-662.
4

(E) Maximize and prioritize the allocation of grid
5

planning benefits to environmental justice and
6

economically disadvantaged customers and communities,
7

such that all metrics provide equitable benefits
8

across the utility's service territory and maintain
9

and improve utility customers' access to uninterrupted
10

utility services.
11

(4) The Commission may establish new tracking and
12

performance metrics in future Multi-Year Rate Plans to
13

further measure achievement of the outcomes set forth in
14

paragraph (2) of subsection (f) of this Section and the
15

other goals and requirements of this Section.
16

(5) The Commission shall also evaluate metrics that
17

were established in prior Multi-Year Rate Plans to
18

determine if there has been an unanticipated material
19

change in circumstances such that adjustments are required
20

to improve the likelihood of the outcomes described in
21

paragraph (2) of subsection (f). For metrics that were
22

established in prior Multi-Year Rate Plan proceedings and
23

that the Commission elects to continue, the design of
24

these metrics, including the goals of tracking metrics and
25

the targets and incentive levels and structures of
26

performance metrics, may be adjusted pursuant to the

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requirements in this Section. The Commission may also
2

change, adjust, or phase out tracking and performance
3

metrics that were established in prior Multi-Year Rate
4

Plan proceedings if these metrics no longer meet the
5

requirements of this Section or if they are rendered
6

obsolete by the changing needs and technology of an
7

evolving grid. Additionally, performance metrics that no
8

longer require an incentive to create improved utility
9

performance may become tracking metrics in a Multi-Year
10

Rate Plan proceeding.
11

(6) The Commission shall initiate a workshop process
12

no later than August 1, 2021, or 15 days after September
13

15, 2021 (the effective date of Public Act 102-662),
14

whichever is later, for the purpose of facilitating the
15

development of metrics for each utility. The workshop
16

shall be coordinated by the staff of the Commission, or a
17

facilitator retained by staff, and shall be organized and
18

facilitated in a manner that encourages representation
19

from diverse stakeholders and ensures equitable
20

opportunities for participation, without requiring formal
21

intervention or representation by an attorney. Working
22

with staff of the Commission the facilitator may conduct a
23

combination of workshops specific to a utility or
24

applicable to multiple utilities where content and
25

stakeholders are substantially similar. The workshop
26

process shall conclude no later than October 31, 2021.

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Following the workshop, the staff of the Commission, or
2

the facilitator retained by the Staff, shall prepare and
3

submit a report to the Commission that identifies the
4

participants in the process, the metrics proposed during
5

the process, any material issues that remained unresolved
6

at the conclusions of such process, and any
7

recommendations for workshop process improvements. Any
8

workshop participant may file comments and reply comments
9

in response to the Staff report.
10

(A) No later than January, 20, 2022, each electric
11

utility that intends to file a petition pursuant to
12

subsection (b) of this Section shall file a petition
13

with the Commission seeking approval of its
14

performance metrics, which shall include for each
15

metric, at a minimum, (i) a detailed description, (ii)
16

the calculation of the baseline, (iii) the performance
17

period and overall performance goal, provided that the
18

performance period shall not commence prior to January
19

1, 2024, (iv) each annual performance goal, (v) the
20

performance adjustment, which shall be a symmetrical
21

basis point increase or decrease to the utility's cost
22

of equity based on the extent to which the utility
23

achieved the annual performance goal, and (vi) the new
24

or modified tariff mechanism that will apply the
25

performance adjustments. The Commission shall issue
26

its order approving, or approving with modification,

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the utility's proposed performance metrics no later
2

than September 30, 2022.
3

(B) No later than August 1, 2025, the Commission
4

shall initiate a workshop process that conforms to the
5

workshop purpose and requirements of this paragraph
6

(6) of this Section to the extent they do not conflict.
7

The workshop process shall conclude no later than
8

October 31, 2025, and the staff of the Commission, or
9

the facilitator retained by the Staff, shall prepare
10

and submit a report consistent with the requirements
11

described in this paragraph (6) of this Section. No
12

later than January 20, 2026, each electric utility
13

subject to the requirements of this Section shall file
14

a petition the reflects, and is consistent with, the
15

components required in this paragraph (6) of this
16

Section, and the Commission shall issue its order
17

approving, or approving with modification, the
18

utility's proposed performance metrics no later than
19

September 30, 2026.
20

(f) On May 1 of each year, following the approval of the
21
first Multi-Year Rate Plan and its initial year, the
22
Commission shall open an annual performance evaluation
23
proceeding to evaluate the utilities' performance on their
24
metric targets during the year just completed, as well as the
25
appropriate Annual Adjustment as defined in paragraph (6). The
26
Commission shall determine the performance and annual

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1
adjustments to be applied through a surcharge in the following
2
calendar year.
3

(1) On February 15 of each year, prior to the annual
4

performance evaluation proceeding, each utility shall file
5

a performance evaluation report with the Commission that
6

includes a description of and all data supporting how the
7

utility performed under each performance metric and an
8

identification of any extraordinary events that adversely
9

impacted the utility's performance.
10

(2) The metrics approved under this Section are based
11

on the assumptions that the utility may fully implement
12

the technology and equipment, and make the investments,
13

required to achieve the metrics and performance goals. If
14

the utility is unable to meet the metrics and performance
15

goals because it was hindered by unanticipated technology
16

or equipment implementation delays, government-declared
17

emergencies, or other investment impediments, then the
18

utility shall be permitted to file a petition with the
19

Commission on or before the date that its report is due
20

pursuant to paragraph (1) of this subsection (f)
21

requesting that the utility be excused from compliance
22

with the applicable performance goal or goals. The burden
23

of proof shall be on the utility, consistent with Article
24

IX, and the utility's petition shall be supported by
25

substantial evidence. No later than 90 days after the
26

utility files its petition, the Commission shall, after

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notice and hearing, enter its order approving or denying,
2

in whole or in part, the utility's petition based on the
3

extent to which the utility demonstrated that its
4

achievement of the affected metrics and performance goals
5

was hindered by unanticipated technology or equipment
6

implementation delays, or other investment impediments,
7

that were reasonably outside of the utility's control.
8

(3) The electric utility shall provide for an annual
9

independent evaluation of its performance on metrics. The
10

independent evaluator shall review the utility's
11

assumptions, baselines, targets, calculation
12

methodologies, and other relevant information, especially
13

ensuring that the utility's data for establishing
14

baselines matches actual performance, and shall provide a
15

report to the Commission in each annual performance
16

evaluation describing the results. The independent
17

evaluator shall present this report as evidence as a
18

nonparty participant and shall not be represented by the
19

utility's legal counsel. The independent evaluator shall
20

be hired through a competitive bidding process with
21

approval of the contract by the Commission.
22

The Commission shall consider the report of the
23

independent evaluator in determining the utility's
24

achievement of performance targets. Discrepancies between
25

the utility's assumptions, baselines, targets, or
26

calculations and those of the independent evaluator shall

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be closely scrutinized by the Commission. If the
2

Commission finds that the utility's reported data for any
3

metric or metrics significantly and incorrectly deviates
4

from the data reported by the independent evaluator, then
5

the Commission shall order the utility to revise its data
6

collection and calculation process within 60 days, with
7

specifications where appropriate.
8

(4) The Commission shall, after notice and hearing in
9

the annual performance evaluation proceeding, enter an
10

order approving the utility's performance adjustment based
11

on its achievement of or failure to achieve its
12

performance targets no later than December 20 each year.
13

The Commission-approved penalties or incentives shall be
14

applied beginning with the next calendar year.
15

(5) In order to promote the transparency of utility
16

investments during the effective period of a multi-year
17

rate plan, inform the Commission's investigation and
18

adjustment of rates in the annual adjustment process, and
19

to facilitate the participation of stakeholders in the
20

annual adjustment process, an electric utility with an
21

effective Multi-Year Rate Plan shall, within 90 days of
22

the close of each quarter during the Multi-Year Rate Plan
23

period, submit to the Commission a report that summarizes
24

the additions to utility plant that were placed into
25

service during the prior quarter, which for purposes of
26

the report shall be the most recently closed fiscal

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quarter. The report shall also summarize the utility plant
2

the electric utility projects it will place into service
3

through the end of the calendar year in which the report is
4

filed. The projections, estimates, plans, and
5

forward-looking information that are provided in the
6

reports pursuant to this paragraph (5) are for planning
7

purposes and are intended to be illustrative of the
8

investments that the utility proposes to make as of the
9

time of submittal. Nothing in this paragraph (5)
10

precludes, or is intended to limit, a utility's ability to
11

modify and update its projections, estimates, plans, and
12

forward-looking information previously submitted in order
13

to reflect stakeholder input or other new or updated
14

information and analysis, including, but not limited to,
15

changes in specific investment needs, customer electric
16

use patterns, customer applications and preferences, and
17

commercially available equipment and technologies, however
18

the utility shall explain any changes or deviations
19

between the projected investments from the quarterly
20

reports and actual investments in the annual report. The
21

reports submitted pursuant to this subsection are intended
22

to be flexible planning tools, and are expected to evolve
23

as new information becomes available. Within 7 days of
24

receiving a quarterly report, the Commission shall timely
25

make such report available to the public by posting it on
26

the Commission's website. Each quarterly report shall

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include the following detail:
2

(A) The total dollar value of the additions to
3

utility plant placed in service during the prior
4

quarter;
5

(B) A list of the major investment categories the
6

electric utility used to manage its routine standing
7

operational activities during the prior quarter
8

including the total dollar amount for the work
9

reflected in each investment category in which utility
10

plant in service is equal to or greater than
11

$2,000,000 for an electric utility that serves more
12

than 3,000,000 customers in the State or $500,000 for
13

an electric utility that serves less than 3,000,000
14

customers but more than 500,000 customers in the State
15

as of the last day of the quarterly reporting period,
16

as well as a summary description of each investment
17

category;
18

(C) A list of the projects which the electric
19

utility has identified by a unique investment tracking
20

number for utility plant placed in service during the
21

prior quarter for utility plant placed in service with
22

a total dollar value as of the last day of the
23

quarterly reporting period that is equal to or greater
24

than $2,000,000 for an electric utility that serves
25

more than 3,000,000 customers in the State or $500,000
26

for an electric utility that serves less than

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3,000,000 retail customers but more than $500,000
2

retail customers in the State, as well as a summary of
3

each project;
4

(D) The estimated total dollar value of the
5

additions to utility plant projected to be placed in
6

service through the end of the calendar year in which
7

the report is filed;
8

(E) A list of the major investment categories the
9

electric utility used to manage its routine standing
10

operational activities with utility plant projected to
11

be placed in service through the end of the calendar
12

year in which the report is filed, including the total
13

dollar amount for the work reflected in each
14

investment category in which utility plant in service
15

is projected to be equal to or greater than $2,000,000
16

for an electric utility that serves more than
17

3,000,000 customers in the State or $500,000 for an
18

electric utility that serves less than 3,000,000
19

retail customers but more than 500,000 retail
20

customers in the State, as well as a summary
21

description of each investment category; and
22

(F) A list of the projects for which the electric
23

utility has identified by a unique investment tracking
24

number for utility plant projected to be placed in
25

service through the end of the calendar year in which
26

the report is filed with an estimated dollar value

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that is equal to or greater than $2,000,000 for an
2

electric utility that serves more than 3,000,000
3

customers in the State or $500,000 for an electric
4

utility that serves less than 3,000,000 retails
5

customers but more than $500,000 retail customers in
6

the State, as well as a summary description of each
7

project.
8

(6) As part of the Annual Performance Adjustment, the
9

electric utility shall submit evidence sufficient to
10

support a determination of its actual revenue requirement
11

for the applicable calendar year, consistent with the
12

provisions of paragraphs (d) and (f) of this subsection.
13

The electric utility shall bear the burden of
14

demonstrating that its costs were prudent and reasonable,
15

subject to the provisions of paragraph (4) of this
16

subsection (f). The Commission's review of the electric
17

utility's annual adjustment shall be based on the same
18

evidentiary standards, including, but not limited to,
19

those concerning the prudence and reasonableness of the
20

known and measurable costs forecasted to be incurred by
21

the utility, and the used and usefulness of the actual
22

plant investment pursuant to Section 9-211 of this Act,
23

that the Commission applies in a proceeding to review a
24

filing for changes in rates pursuant to Section 9-201 of
25

this Act. The Commission shall determine the prudence and
26

reasonableness of the actual costs incurred by the utility

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during the applicable calendar year, as well as determine
2

the original cost of plant in service as of the end of the
3

applicable calendar year. The Commission shall then
4

determine the Annual Adjustment, which shall mean the
5

amount by which, the electric utility's actual revenue
6

requirement for the applicable year of the Multi-Year Rate
7

Plan either exceeded, or was exceeded by, the revenue
8

requirement approved by the Commission for such calendar
9

year, plus carrying costs calculated at the weighted
10

average cost of capital approved for the Multi-Year Rate
11

Plan.
12

The Commission's determination of the electric
13

utility's actual revenue requirement for the applicable
14

calendar year shall be based on:
15

(A) the Commission-approved used and useful,
16

prudent and reasonable actual costs for the applicable
17

calendar year, which shall be determined pursuant to
18

the following criteria:
19

(i) the overall level of actual costs incurred
20

during the calendar year, provided that the
21

Commission may not allow recovery of actual costs
22

that are more than 105% of the approved revenue
23

requirement calculated as provided in item (ii) of
24

this subparagraph (A), except to the extent the
25

Commission approves a modification of the
26

Multi-Year Rate Plan to permit such recovery;

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(ii) the calculation of 105% of the revenue
2

requirement required by this subparagraph (A)
3

shall exclude the revenue requirement impacts of
4

the following volatile and fluctuating variables
5

that occurred during the year: (i) storms and
6

weather-related events for which the utility
7

provides sufficient evidence to demonstrate that
8

such expenses were not foreseeable and not in
9

control of the utility; (ii) new business; (iii)
10

changes in interest rates; (iv) changes in taxes;
11

(v) facility relocations; (vi) changes in pension
12

or post-retirement benefits costs due to
13

fluctuations in interest rates, market returns or
14

actuarial assumptions; (vii) amortization expenses
15

related to costs; and (viii) changes in the timing
16

of when an expenditure or investment is made such
17

that it is accelerated to occur during the
18

applicable year or deferred to occur in a
19

subsequent year;
20

(B) the year-end rate base;
21

(C) the cost of equity approved in the multi-year
22

rate plan; and
23

(D) the electric utility's actual year-end capital
24

structure, provided that the common equity ratio in
25

such capital structure may not exceed the common
26

equity ratio that was approved by the Commission in

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the Multi-Year Rate Plan.
2

(2) The Commission's determinations of the prudence
3

and reasonableness of the costs incurred for the
4

applicable year, and of the original cost of plant in
5

service as of the end of the applicable calendar year,
6

shall be final upon entry of the Commission's order and
7

shall not be subject to collateral attack in any other
8

Commission proceeding, case, docket, order, rule, or
9

regulation; however, nothing in this Section shall
10

prohibit a party from petitioning the Commission to rehear
11

or appeal to the courts the order pursuant to the
12

provisions of this Act.
13

(g) During the period leading to approval of the first
14
Multi-Year Integrated Grid Plan, each electric utility will
15
necessarily continue to invest in its distribution grid. Those
16
investments will be subject to a determination of prudence and
17
reasonableness consistent with Commission practice and law.
18
Any failure to conform to the Multi-Year Integrated Grid Plan
19
ultimately approved shall not imply imprudence or
20
unreasonableness.
21

(h) After calculating the Performance Adjustment and
22
Annual Adjustment, the Commission shall order the electric
23
utility to collect the amount in excess of the revenue
24
requirement from customers, or issue a refund to customers, as
25
applicable, to be applied through a surcharge beginning with
26
the next calendar year.

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Electric utilities subject to the requirements of this
2
Section shall be permitted to file new or revised tariffs to
3
comply with the provisions of, and Commission orders entered
4
pursuant to, this Section.
5
(Source: P.A. 104-417, eff. 8-15-25; revised 12-12-25.)

6

Section 15.
The Environmental Protection Act is amended by
7
changing Section 9.15 as follows:

8

(415 ILCS 5/9.15)
9

(Text of Section before amendment by P.A. 104-458
)
10

Sec. 9.15.
Greenhouse gases.
11

(a) An air pollution construction permit shall not be
12
required due to emissions of greenhouse gases if the
13
equipment, site, or source is not subject to regulation, as
14
defined by 40 CFR 52.21, as now or hereafter amended, for
15
greenhouse gases or is otherwise not addressed in this Section
16
or by the Board in regulations for greenhouse gases. These
17
exemptions do not relieve an owner or operator from the
18
obligation to comply with other applicable rules or
19
regulations.
20

(b) An air pollution operating permit shall not be
21
required due to emissions of greenhouse gases if the
22
equipment, site, or source is not subject to regulation, as
23
defined by Section 39.5 of this Act, for greenhouse gases or is
24
otherwise not addressed in this Section or by the Board in

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1
regulations for greenhouse gases. These exemptions do not
2
relieve an owner or operator from the obligation to comply
3
with other applicable rules or regulations.
4

(c) (Blank).
5

(d) (Blank).
6

(e) (Blank).
7

(f) As used in this Section:
8

"Carbon dioxide emission" means the plant annual CO
2
total
9
output emission as measured by the United States Environmental
10
Protection Agency in its Emissions & Generation Resource
11
Integrated Database (eGrid), or its successor.
12

"Carbon dioxide equivalent emissions" or "CO
2
e" means the
13
sum total of the mass amount of emissions in tons per year,
14
calculated by multiplying the mass amount of each of the 6
15
greenhouse gases specified in Section 3.207, in tons per year,
16
by its associated global warming potential as set forth in 40
17
CFR 98, subpart A, table A-1 or its successor, and then adding
18
them all together.
19

"Cogeneration" or "combined heat and power" refers to any
20
system that, either simultaneously or sequentially, produces
21
electricity and useful thermal energy from a single fuel
22
source.
23

"Copollutants" refers to the 6 criteria pollutants that
24
have been identified by the United States Environmental
25
Protection Agency pursuant to the Clean Air Act.
26

"Electric generating unit" or "EGU" means a fossil

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1
fuel-fired stationary boiler, combustion turbine, or combined
2
cycle system that serves a generator that has a nameplate
3
capacity greater than 25 MWe and produces electricity for
4
sale.
5

"Environmental justice community" means the definition of
6
that term based on existing methodologies and findings, used
7
and as may be updated by the Illinois Power Agency and its
8
program administrator in the Illinois Solar for All Program.
9

"Equity investment eligible community" or "eligible
10
community" means the geographic areas throughout Illinois that
11
would most benefit from equitable investments by the State
12
designed to combat discrimination and foster sustainable
13
economic growth. Specifically, eligible community means the
14
following areas:
15

(1) areas where residents have been historically
16

excluded from economic opportunities, including
17

opportunities in the energy sector, as defined as R3 areas
18

pursuant to Section 10-40 of the Cannabis Regulation and
19

Tax Act; and
20

(2) areas where residents have been historically
21

subject to disproportionate burdens of pollution,
22

including pollution from the energy sector, as established
23

by environmental justice communities as defined by the
24

Illinois Power Agency pursuant to the Illinois Power
25

Agency Act, excluding any racial or ethnic indicators.
26

"Equity investment eligible person" or "eligible person"

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1
means the persons who would most benefit from equitable
2
investments by the State designed to combat discrimination and
3
foster sustainable economic growth. Specifically, eligible
4
person means the following people:
5

(1) persons whose primary residence is in an equity
6

investment eligible community;
7

(2) persons whose primary residence is in a
8

municipality, or a county with a population under 100,000,
9

where the closure of an electric generating unit or mine
10

has been publicly announced or the electric generating
11

unit or mine is in the process of closing or closed within
12

the last 5 years;
13

(3) persons who are graduates of or currently enrolled
14

in the foster care system; or
15

(4) persons who were formerly incarcerated.
16

"Existing emissions" means:
17

(1) for CO
2
e, the total average tons-per-year of CO
2
e
18

emitted by the EGU or large GHG-emitting unit either in
19

the years 2018 through 2020 or, if the unit was not yet in
20

operation by January 1, 2018, in the first 3 full years of
21

that unit's operation; and
22

(2) for any copollutant, the total average
23

tons-per-year of that copollutant emitted by the EGU or
24

large GHG-emitting unit either in the years 2018 through
25

2020 or, if the unit was not yet in operation by January 1,
26

2018, in the first 3 full years of that unit's operation.

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"Green hydrogen" means a power plant technology in which
2
an EGU creates electric power exclusively from electrolytic
3
hydrogen, in a manner that produces zero carbon and
4
copollutant emissions, using hydrogen fuel that is
5
electrolyzed using a 100% renewable zero carbon emission
6
energy source.
7

"Large greenhouse gas-emitting unit" or "large
8
GHG-emitting unit" means a unit that is an electric generating
9
unit or other fossil fuel-fired unit that itself has a
10
nameplate capacity or serves a generator that has a nameplate
11
capacity greater than 25 MWe and that produces electricity,
12
including, but not limited to, coal-fired, coal-derived,
13
oil-fired, natural gas-fired, and cogeneration units.
14

"NO
x
emission rate" means the plant annual NO
x
total output
15
emission rate as measured by the United States Environmental
16
Protection Agency in its Emissions & Generation Resource
17
Integrated Database (eGrid), or its successor, in the most
18
recent year for which data is available.
19

"Public greenhouse gas-emitting units" or "public
20
GHG-emitting unit" means large greenhouse gas-emitting units,
21
including EGUs, that are wholly owned, directly or indirectly,
22
by one or more municipalities, municipal corporations, joint
23
municipal electric power agencies, electric cooperatives, or
24
other governmental or nonprofit entities, whether organized
25
and created under the laws of Illinois or another state.
26

"SO
2
emission rate" means the "plant annual SO
2
total

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1
output emission rate" as measured by the United States
2
Environmental Protection Agency in its Emissions & Generation
3
Resource Integrated Database (eGrid), or its successor, in the
4
most recent year for which data is available.
5

(g) All EGUs and large greenhouse gas-emitting units that
6
use coal or oil as a fuel and are not public GHG-emitting units
7
shall permanently reduce all CO
2
e and copollutant emissions to
8
zero no later than January 1, 2030.
9

(h) All EGUs and large greenhouse gas-emitting units that
10
use coal as a fuel and are public GHG-emitting units shall
11
permanently reduce CO
2
e emissions to zero no later than
12
December 31, 2045. Any source or plant with such units must
13
also reduce their CO
2
e emissions by 45% from existing
14
emissions by no later than January 1, 2035. If the emissions
15
reduction requirement is not achieved by December 31, 2035,
16
the plant shall retire one or more units or otherwise reduce
17
its CO
2
e emissions by 45% from existing emissions by June 30,
18
2038.
19

(i) All EGUs and large greenhouse gas-emitting units that
20
use gas as a fuel and are not public GHG-emitting units shall
21
permanently reduce all CO
2
e and copollutant emissions to zero,
22
including through unit retirement or the use of 100% green
23
hydrogen or other similar technology that is commercially
24
proven to achieve zero carbon emissions, according to the
25
following:
26

(1) No later than January 1, 2030: all EGUs and large

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1

greenhouse gas-emitting units that have a NO
x
emissions
2

rate of greater than 0.12 lbs/MWh or a SO
2
emission rate of
3

greater than 0.006 lb/MWh, and are located in or within 3
4

miles of an environmental justice community designated as
5

of January 1, 2021 or an equity investment eligible
6

community.
7

(2) No later than January 1, 2040: all EGUs and large
8

greenhouse gas-emitting units that have a NO
x
emission
9

rate of greater than 0.12 lbs/MWh or a SO
2
emission rate
10

greater than 0.006 lb/MWh, and are not located in or
11

within 3 miles of an environmental justice community
12

designated as of January 1, 2021 or an equity investment
13

eligible community. After January 1, 2035, each such EGU
14

and large greenhouse gas-emitting unit shall reduce its
15

CO
2
e emissions by at least 50% from its existing emissions
16

for CO
2
e, and shall be limited in operation to, on average,
17

6 hours or less per day, measured over a calendar year, and
18

shall not run for more than 24 consecutive hours except in
19

emergency conditions, as designated by a Regional
20

Transmission Organization or Independent System Operator.
21

(3) No later than January 1, 2035: all EGUs and large
22

greenhouse gas-emitting units that began operation prior
23

to the effective date of this amendatory Act of the 102nd
24

General Assembly and have a NO
x
emission rate of less than
25

or equal to 0.12 lb/MWh and a SO
2
emission rate less than
26

or equal to 0.006 lb/MWh, and are located in or within 3

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1

miles of an environmental justice community designated as
2

of January 1, 2021 or an equity investment eligible
3

community. Each such EGU and large greenhouse gas-emitting
4

unit shall reduce its CO
2
e emissions by at least 50% from
5

its existing emissions for CO
2
e no later than January 1,
6

2030.
7

(4) No later than January 1, 2040: All remaining EGUs
8

and large greenhouse gas-emitting units that have a heat
9

rate greater than or equal to 7000 BTU/kWh. Each such EGU
10

and Large greenhouse gas-emitting unit shall reduce its
11

CO
2
e emissions by at least 50% from its existing emissions
12

for CO
2
e no later than January 1, 2035.
13

(5) No later than January 1, 2045: all remaining EGUs
14

and large greenhouse gas-emitting units.
15

(j) All EGUs and large greenhouse gas-emitting units that
16
use gas as a fuel and are public GHG-emitting units shall
17
permanently reduce all CO
2
e and copollutant emissions to zero,
18
including through unit retirement or the use of 100% green
19
hydrogen or other similar technology that is commercially
20
proven to achieve zero carbon emissions by January 1, 2045.
21

(k) All EGUs and large greenhouse gas-emitting units that
22
utilize combined heat and power or cogeneration technology
23
shall permanently reduce all CO
2
e and copollutant emissions to
24
zero, including through unit retirement or the use of 100%
25
green hydrogen or other similar technology that is
26
commercially proven to achieve zero carbon emissions by

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1
January 1, 2045.
2

(k-5) No EGU or large greenhouse gas-emitting unit that
3
uses gas as a fuel and is not a public GHG-emitting unit may
4
emit, in any 12-month period, CO
2
e or copollutants in excess of
5
that unit's existing emissions for those pollutants.
6

(l) Notwithstanding subsections (g) through (k-5), large
7
GHG-emitting units including EGUs may temporarily continue
8
emitting CO
2
e and copollutants after any applicable deadline
9
specified in any of subsections (g) through (k-5) if it has
10
been determined, as described in paragraphs (1) and (2) of
11
this subsection, that ongoing operation of the EGU is
12
necessary to maintain power grid supply and reliability or
13
ongoing operation of large GHG-emitting unit that is not an
14
EGU is necessary to serve as an emergency backup to
15
operations. Up to and including the occurrence of an emission
16
reduction deadline under subsection (i), all EGUs and large
17
GHG-emitting units must comply with the following terms:
18

(1) if an EGU or large GHG-emitting unit that is a
19

participant in a regional transmission organization
20

intends to retire, it must submit documentation to the
21

appropriate regional transmission organization by the
22

appropriate deadline that meets all applicable regulatory
23

requirements necessary to obtain approval to permanently
24

cease operating the large GHG-emitting unit;
25

(2) if any EGU or large GHG-emitting unit that is a
26

participant in a regional transmission organization

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1

receives notice that the regional transmission
2

organization has determined that continued operation of
3

the unit is required, the unit may continue operating
4

until the issue identified by the regional transmission
5

organization is resolved. The owner or operator of the
6

unit must cooperate with the regional transmission
7

organization in resolving the issue and must reduce its
8

emissions to zero, consistent with the requirements under
9

subsection (g), (h), (i), (j), (k), or (k-5), as
10

applicable, as soon as practicable when the issue
11

identified by the regional transmission organization is
12

resolved; and
13

(3) any large GHG-emitting unit that is not a
14

participant in a regional transmission organization shall
15

be allowed to continue emitting CO
2
e and copollutants
16

after the zero-emission date specified in subsection (g),
17

(h), (i), (j), (k), or (k-5), as applicable, in the
18

capacity of an emergency backup unit if approved by the
19

Illinois Commerce Commission.
20

(m) No variance, adjusted standard, or other regulatory
21
relief otherwise available in this Act may be granted to the
22
emissions reduction and elimination obligations in this
23
Section.
24

(n) By June 30 of each year, beginning in 2025, the Agency
25
shall prepare and publish on its website a report setting
26
forth the actual greenhouse gas emissions from individual

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1
units and the aggregate statewide emissions from all units for
2
the prior year.
3

(o) Every 5 years beginning in 2025, the Environmental
4
Protection Agency, Illinois Power Agency, and Illinois
5
Commerce Commission shall jointly prepare, and release
6
publicly, a report to the General Assembly that examines the
7
State's current progress toward its renewable energy resource
8
development goals, the status of CO
2
e and copollutant
9
emissions reductions, the current status and progress toward
10
developing and implementing green hydrogen technologies, the
11
current and projected status of electric resource adequacy and
12
reliability throughout the State for the period beginning 5
13
years ahead, and proposed solutions for any findings. The
14
Environmental Protection Agency, Illinois Power Agency, and
15
Illinois Commerce Commission shall consult PJM
16
Interconnection, LLC and Midcontinent Independent System
17
Operator, Inc., or their respective successor organizations
18
regarding forecasted resource adequacy and reliability needs,
19
anticipated new generation interconnection, new transmission
20
development or upgrades, and any announced large GHG-emitting
21
unit closure dates and include this information in the report.
22
The report shall be released publicly by no later than
23
December 15 of the year it is prepared. If the Environmental
24
Protection Agency, Illinois Power Agency, and Illinois
25
Commerce Commission jointly conclude in the report that the
26
data from the regional grid operators, the pace of renewable

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1
energy development, the pace of development of energy storage
2
and demand response utilization, transmission capacity, and
3
the CO
2
e and copollutant emissions reductions required by
4
subsection (i) or (k-5) reasonably demonstrate that a resource
5
adequacy shortfall will occur, including whether there will be
6
sufficient in-state capacity to meet the zonal requirements of
7
MISO Zone 4 or the PJM ComEd Zone, per the requirements of the
8
regional transmission organizations, or that the regional
9
transmission operators determine that a reliability violation
10
will occur during the time frame the study is evaluating, then
11
the Illinois Power Agency, in conjunction with the
12
Environmental Protection Agency shall develop a plan to reduce
13
or delay CO
2
e and copollutant emissions reductions
14
requirements only to the extent and for the duration necessary
15
to meet the resource adequacy and reliability needs of the
16
State, including allowing any plants whose emission reduction
17
deadline has been identified in the plan as creating a
18
reliability concern to continue operating, including operating
19
with reduced emissions or as emergency backup where
20
appropriate. The plan shall also consider the use of renewable
21
energy, energy storage, demand response, transmission
22
development, or other strategies to resolve the identified
23
resource adequacy shortfall or reliability violation.
24

(1) In developing the plan, the Environmental
25

Protection Agency and the Illinois Power Agency shall hold
26

at least one workshop open to, and accessible at a time and

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1

place convenient to, the public and shall consider any
2

comments made by stakeholders or the public. Upon
3

development of the plan, copies of the plan shall be
4

posted and made publicly available on the Environmental
5

Protection Agency's, the Illinois Power Agency's, and the
6

Illinois Commerce Commission's websites. All interested
7

parties shall have 60 days following the date of posting
8

to provide comment to the Environmental Protection Agency
9

and the Illinois Power Agency on the plan. All comments
10

submitted to the Environmental Protection Agency and the
11

Illinois Power Agency shall be encouraged to be specific,
12

supported by data or other detailed analyses, and, if
13

objecting to all or a portion of the plan, accompanied by
14

specific alternative wording or proposals. All comments
15

shall be posted on the Environmental Protection Agency's,
16

the Illinois Power Agency's, and the Illinois Commerce
17

Commission's websites. Within 30 days following the end of
18

the 60-day review period, the Environmental Protection
19

Agency and the Illinois Power Agency shall revise the plan
20

as necessary based on the comments received and file its
21

revised plan with the Illinois Commerce Commission for
22

approval.
23

(2) Within 60 days after the filing of the revised
24

plan at the Illinois Commerce Commission, any person
25

objecting to the plan shall file an objection with the
26

Illinois Commerce Commission. Within 30 days after the

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expiration of the comment period, the Illinois Commerce
2

Commission shall determine whether an evidentiary hearing
3

is necessary. The Illinois Commerce Commission shall also
4

host 3 public hearings within 90 days after the plan is
5

filed. Following the evidentiary and public hearings, the
6

Illinois Commerce Commission shall enter its order
7

approving or approving with modifications the reliability
8

mitigation plan within 180 days.
9

(3) The Illinois Commerce Commission shall only
10

approve the plan if the Illinois Commerce Commission
11

determines that it will resolve the resource adequacy or
12

reliability deficiency identified in the reliability
13

mitigation plan at the least amount of CO
2
e and copollutant
14

emissions, taking into consideration the emissions impacts
15

on environmental justice communities, and that it will
16

ensure adequate, reliable, affordable, efficient, and
17

environmentally sustainable electric service at the lowest
18

total cost over time, taking into account the impact of
19

increases in emissions.
20

(4) If the resource adequacy or reliability deficiency
21

identified in the reliability mitigation plan is resolved
22

or reduced, the Environmental Protection Agency and the
23

Illinois Power Agency may file an amended plan adjusting
24

the reduction or delay in CO
2
e and copollutant emission
25

reduction requirements identified in the plan.
26
(Source: P.A. 102-662, eff. 9-15-21; 102-1031, eff. 5-27-22.)

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1

(Text of Section after amendment by P.A. 104-458
)
2

Sec. 9.15.
Greenhouse gases.
3

(a) An air pollution construction permit shall not be
4
required due to emissions of greenhouse gases if the
5
equipment, site, or source is not subject to regulation, as
6
defined by 40 CFR 52.21, as now or hereafter amended, for
7
greenhouse gases or is otherwise not addressed in this Section
8
or by the Board in regulations for greenhouse gases. These
9
exemptions do not relieve an owner or operator from the
10
obligation to comply with other applicable rules or
11
regulations.
12

(b) An air pollution operating permit shall not be
13
required due to emissions of greenhouse gases if the
14
equipment, site, or source is not subject to regulation, as
15
defined by Section 39.5 of this Act, for greenhouse gases or is
16
otherwise not addressed in this Section or by the Board in
17
regulations for greenhouse gases. These exemptions do not
18
relieve an owner or operator from the obligation to comply
19
with other applicable rules or regulations.
20

(c) (Blank).
21

(d) (Blank).
22

(e) (Blank).
23

(f) As used in this Section:
24

"Carbon dioxide emission" means the plant annual CO
2
total
25
output emission as measured by the United States Environmental

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1
Protection Agency in its Emissions & Generation Resource
2
Integrated Database (eGrid), or its successor.
3

"Carbon dioxide equivalent emissions" or "CO
2
e" means the
4
sum total of the mass amount of emissions in tons per year,
5
calculated by multiplying the mass amount of each of the 6
6
greenhouse gases specified in Section 3.207, in tons per year,
7
by its associated global warming potential as set forth in 40
8
CFR 98, subpart A, table A-1 or its successor, and then adding
9
them all together.
10

"Cogeneration" or "combined heat and power" refers to any
11
system that, either simultaneously or sequentially, produces
12
electricity and useful thermal energy from a single fuel
13
source.
14

"Copollutants" refers to the 6 criteria pollutants that
15
have been identified by the United States Environmental
16
Protection Agency pursuant to the Clean Air Act.
17

"Electric generating unit" or "EGU" means a fossil
18
fuel-fired stationary boiler, combustion turbine, or combined
19
cycle system that serves a generator that has a nameplate
20
capacity greater than 25 MWe and produces electricity for
21
sale.
22

"Environmental justice community" means the definition of
23
that term based on existing methodologies and findings, used
24
and as may be updated by the Illinois Power Agency and its
25
program administrator in the Illinois Solar for All Program.
26

"Equity investment eligible community" or "eligible

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1
community" means the geographic areas throughout Illinois that
2
would most benefit from equitable investments by the State
3
designed to combat discrimination and foster sustainable
4
economic growth. Specifically, eligible community means the
5
following areas:
6

(1) areas where residents have been historically
7

excluded from economic opportunities, including
8

opportunities in the energy sector, as defined as R3 areas
9

pursuant to Section 10-40 of the Cannabis Regulation and
10

Tax Act; and
11

(2) areas where residents have been historically
12

subject to disproportionate burdens of pollution,
13

including pollution from the energy sector, as established
14

by environmental justice communities as defined by the
15

Illinois Power Agency pursuant to the Illinois Power
16

Agency Act, excluding any racial or ethnic indicators.
17

"Equity investment eligible person" or "eligible person"
18
means the persons who would most benefit from equitable
19
investments by the State designed to combat discrimination and
20
foster sustainable economic growth. Specifically, eligible
21
person means the following people:
22

(1) persons whose primary residence is in an equity
23

investment eligible community;
24

(2) persons whose primary residence is in a
25

municipality, or a county with a population under 100,000,
26

where the closure of an electric generating unit or mine

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1

has been publicly announced or the electric generating
2

unit or mine is in the process of closing or closed within
3

the last 5 years;
4

(3) persons who are graduates of or currently enrolled
5

in the foster care system; or
6

(4) persons who were formerly incarcerated.
7

"Existing emissions" means:
8

(1) for CO
2
e, the total average tons-per-year of CO
2
e
9

emitted by the EGU or large GHG-emitting unit either in
10

the years 2018 through 2020 or, if the unit was not yet in
11

operation by January 1, 2018, in the first 3 full years of
12

that unit's operation; and
13

(2) for any copollutant, the total average
14

tons-per-year of that copollutant emitted by the EGU or
15

large GHG-emitting unit either in the years 2018 through
16

2020 or, if the unit was not yet in operation by January 1,
17

2018, in the first 3 full years of that unit's operation.
18

"Green hydrogen" means a power plant technology in which
19
an EGU creates electric power exclusively from electrolytic
20
hydrogen, in a manner that produces zero carbon and
21
copollutant emissions, using hydrogen fuel that is
22
electrolyzed using a 100% renewable zero carbon emission
23
energy source.
24

"Large greenhouse gas-emitting unit" or "large
25
GHG-emitting unit" means a unit that is an electric generating
26
unit or other fossil fuel-fired unit that itself has a

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1
nameplate capacity or serves a generator that has a nameplate
2
capacity greater than 25 MWe and that produces electricity,
3
including, but not limited to, coal-fired, coal-derived,
4
oil-fired, natural gas-fired, and cogeneration units.
5

"NO
x
emission rate" means the plant annual NO
x
total output
6
emission rate as measured by the United States Environmental
7
Protection Agency in its Emissions & Generation Resource
8
Integrated Database (eGrid), or its successor, in the most
9
recent year for which data is available.
10

"Public greenhouse gas-emitting units" or "public
11
GHG-emitting unit" means large greenhouse gas-emitting units,
12
including EGUs, that are wholly owned, directly or indirectly,
13
by one or more municipalities, municipal corporations, joint
14
municipal electric power agencies, electric cooperatives, or
15
other governmental or nonprofit entities, whether organized
16
and created under the laws of Illinois or another state.
17

"SO
2
emission rate" means the "plant annual SO
2
total
18
output emission rate" as measured by the United States
19
Environmental Protection Agency in its Emissions & Generation
20
Resource Integrated Database (eGrid), or its successor, in the
21
most recent year for which data is available.
22

(g) All EGUs and large greenhouse gas-emitting units that
23
use coal or oil as a fuel and are not public GHG-emitting units
24
shall permanently reduce all CO
2
e and copollutant emissions to
25
zero no later than January 1,
2040, or earlier if certified by
26
the Illinois Commerce Commission as cost-effective under a

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1
market-driven analysis under Section Public Utilities Act

2
2030
.
3

(h) All EGUs and large greenhouse gas-emitting units that
4
use coal as a fuel and are public GHG-emitting units shall
5
permanently reduce CO
2
e emissions to zero no later than
6
December 31,
2055, or earlier if certified by the Illinois
7
Commerce Commission as cost-effective under a market-driven
8
analysis analysis under Section Public Utilities Act

2045
. Any
9
source or plant with such units must also reduce their CO
2
e
10
emissions by 45% from existing emissions by no later than
11
January 1, 2035. If the emissions reduction requirement is not
12
achieved by December 31,
2045, or earlier if certified by the
13
Illinois Commerce Commission as cost-effective under a
14
market-driven analysis panalysis under Section Public
15
Utilities Act

2035
, the plant shall retire one or more units or
16
otherwise reduce its CO
2
e emissions by 45% from existing
17
emissions by June 30,
2048

2038
.
18

(i) All EGUs and large greenhouse gas-emitting units that
19
use gas as a fuel and are not public GHG-emitting units shall
20
permanently reduce all CO
2
e and copollutant emissions to zero,
21
including through unit retirement or the use of 100% green
22
hydrogen or other similar technology that is commercially
23
proven to achieve zero carbon emissions, according to the
24
following:
25

(1) No later than January 1, 2030: all EGUs and large
26

greenhouse gas-emitting units that have a NO
x
emissions

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1

rate of greater than 0.12 lbs/MWh or a SO
2
emission rate of
2

greater than 0.006 lb/MWh, and are located in or within 3
3

miles of an environmental justice community designated as
4

of January 1, 2021 or an equity investment eligible
5

community.
6

(2) No later than January 1,
2050 or earlier if
7

certified by the Illinois Commerce Commission as
8

cost-effective under a market-driven analysis analysis
9

under Section Public Utilities Act

2040
: all EGUs and
10

large greenhouse gas-emitting units that have a NO
x

11

emission rate of greater than 0.12 lbs/MWh or a SO
2

12

emission rate greater than 0.006 lb/MWh, and are not
13

located in or within 3 miles of an environmental justice
14

community designated as of January 1, 2021 or an equity
15

investment eligible community. After January 1, 2035, each
16

such EGU and large greenhouse gas-emitting unit shall
17

reduce its CO
2
e emissions by at least 50% from its existing
18

emissions for CO
2
e, and shall be limited in operation to,
19

on average, 6 hours or less per day, measured over a
20

calendar year, and shall not run for more than 24
21

consecutive hours except in emergency conditions, as
22

designated by a Regional Transmission Organization or
23

Independent System Operator.
24

(3) No later than January 1, 2035: all EGUs and large
25

greenhouse gas-emitting units that began operation prior
26

to the effective date of this amendatory Act of the 102nd

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1

General Assembly and have a NO
x
emission rate of less than
2

or equal to 0.12 lb/MWh and a SO
2
emission rate less than
3

or equal to 0.006 lb/MWh, and are located in or within 3
4

miles of an environmental justice community designated as
5

of January 1, 2021 or an equity investment eligible
6

community. Each such EGU and large greenhouse gas-emitting
7

unit shall reduce its CO
2
e emissions by at least 50% from
8

its existing emissions for CO
2
e no later than January 1,
9

2030.
10

(4) No later than January 1, 2040: All remaining EGUs
11

and large greenhouse gas-emitting units that have a heat
12

rate greater than or equal to 7000 BTU/kWh. Each such EGU
13

and Large greenhouse gas-emitting unit shall reduce its
14

CO
2
e emissions by at least 50% from its existing emissions
15

for CO
2
e no later than January 1, 2035.
16

(5) No later than January 1,
2055 or earlier if
17

certified by the Illinois Commerce Commission as
18

cost-effective under a market-driven analysis analysis
19

under Section Public Utilities Act

2045
: all remaining
20

EGUs and large greenhouse gas-emitting units.
21

(j) All EGUs and large greenhouse gas-emitting units that
22
use gas as a fuel and are public GHG-emitting units shall
23
permanently reduce all CO
2
e and copollutant emissions to zero,
24
including through unit retirement or the use of 100% green
25
hydrogen or other similar technology that is commercially
26
proven to achieve zero carbon emissions by January 1, 2045.

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1

(k) All EGUs and large greenhouse gas-emitting units that
2
utilize combined heat and power or cogeneration technology
3
shall permanently reduce all CO
2
e and copollutant emissions to
4
zero, including through unit retirement or the use of 100%
5
green hydrogen or other similar technology that is
6
commercially proven to achieve zero carbon emissions by
7
January 1, 2045.
8

(k-5) No EGU or large greenhouse gas-emitting unit that
9
uses gas as a fuel and is not a public GHG-emitting unit may
10
emit, in any 12-month period, CO
2
e or copollutants in excess of
11
that unit's existing emissions for those pollutants.
12

(l) Notwithstanding subsections (g) through (k-5), large
13
GHG-emitting units including EGUs may temporarily continue
14
emitting CO
2
e and copollutants after any applicable deadline
15
specified in any of subsections (g) through (k-5) if it has
16
been determined, as described in paragraphs (1) and (2) of
17
this subsection, that ongoing operation of the EGU is
18
necessary to maintain power grid supply and reliability or
19
ongoing operation of large GHG-emitting unit that is not an
20
EGU is necessary to serve as an emergency backup to
21
operations. Up to and including the occurrence of an emission
22
reduction deadline under subsection (i), all EGUs and large
23
GHG-emitting units must comply with the following terms:
24

(1) if an EGU or large GHG-emitting unit that is a
25

participant in a regional transmission organization
26

intends to retire, it must submit documentation to the

SB3929
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1

appropriate regional transmission organization by the
2

appropriate deadline that meets all applicable regulatory
3

requirements necessary to obtain approval to permanently
4

cease operating the large GHG-emitting unit;
5

(2) if any EGU or large GHG-emitting unit that is a
6

participant in a regional transmission organization
7

receives notice that the regional transmission
8

organization has determined that continued operation of
9

the unit is required, the unit may continue operating
10

until the issue identified by the regional transmission
11

organization is resolved. The owner or operator of the
12

unit must cooperate with the regional transmission
13

organization in resolving the issue and must reduce its
14

emissions to zero, consistent with the requirements under
15

subsection (g), (h), (i), (j), (k), or (k-5), as
16

applicable, as soon as practicable when the issue
17

identified by the regional transmission organization is
18

resolved; and
19

(3) any large GHG-emitting unit that is not a
20

participant in a regional transmission organization shall
21

be allowed to continue emitting CO
2
e and copollutants
22

after the zero-emission date specified in subsection (g),
23

(h), (i), (j), (k), or (k-5), as applicable, in the
24

capacity of an emergency backup unit if approved by the
25

Illinois Commerce Commission.
26

(m) No variance, adjusted standard, or other regulatory

SB3929
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1
relief otherwise available in this Act may be granted to the
2
emissions reduction and elimination obligations in this
3
Section.
4

(n) By June 30 of each year, beginning in 2025, the Agency
5
shall prepare and publish on its website a report setting
6
forth the actual greenhouse gas emissions from individual
7
units and the aggregate statewide emissions from all units for
8
the prior year.
9

(o) The Environmental Protection Agency, Illinois Power
10
Agency, and Illinois Commerce Commission shall jointly
11
prepare, and release publicly, a report to the General
12
Assembly that examines the State's current progress toward its
13
renewable energy resource development goals, the status of
14
CO
2
e and copollutant emissions reductions, the current status
15
and progress toward developing and implementing green hydrogen
16
technologies, the current and projected status of electric
17
resource adequacy and reliability throughout the State for the
18
period beginning 5 years ahead, and proposed solutions for any
19
findings. The Environmental Protection Agency, Illinois Power
20
Agency, and Illinois Commerce Commission shall consult PJM
21
Interconnection, LLC and Midcontinent Independent System
22
Operator, Inc., or their respective successor organizations
23
regarding forecasted resource adequacy and reliability needs,
24
anticipated new generation interconnection, new transmission
25
development or upgrades, and any announced large GHG-emitting
26
unit closure dates and include this information in the report.

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1
The report shall be released publicly by no later than
2
December 15 of the year it is prepared. If the Environmental
3
Protection Agency, Illinois Power Agency, and Illinois
4
Commerce Commission jointly conclude in the report that the
5
data from the regional grid operators, the pace of renewable
6
energy development, the pace of development of energy storage
7
and demand response utilization, transmission capacity, and
8
the CO
2
e and copollutant emissions reductions required by
9
subsection (i) or (k-5) reasonably demonstrate that a resource
10
adequacy shortfall will occur, including whether there will be
11
sufficient in-state capacity to meet the zonal requirements of
12
MISO Zone 4 or the PJM ComEd Zone, per the requirements of the
13
regional transmission organizations, or that the regional
14
transmission operators determine that a reliability violation
15
will occur during the time frame the study is evaluating, then
16
the Illinois Power Agency, in conjunction with the
17
Environmental Protection Agency shall develop a plan to reduce
18
or delay CO
2
e and copollutant emissions reductions
19
requirements only to the extent and for the duration necessary
20
to meet the resource adequacy and reliability needs of the
21
State, including allowing any plants whose emission reduction
22
deadline has been identified in the plan as creating a
23
reliability concern to continue operating, including operating
24
with reduced emissions or as emergency backup where
25
appropriate. The plan shall also consider the use of renewable
26
energy, energy storage, demand response, transmission

SB3929
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1
development, or other strategies to resolve the identified
2
resource adequacy shortfall or reliability violation.
3

(1) In developing the plan, the Environmental
4

Protection Agency and the Illinois Power Agency shall hold
5

at least one workshop open to, and accessible at a time and
6

place convenient to, the public and shall consider any
7

comments made by stakeholders or the public. Upon
8

development of the plan, copies of the plan shall be
9

posted and made publicly available on the Environmental
10

Protection Agency's, the Illinois Power Agency's, and the
11

Illinois Commerce Commission's websites. All interested
12

parties shall have 60 days following the date of posting
13

to provide comment to the Environmental Protection Agency
14

and the Illinois Power Agency on the plan. All comments
15

submitted to the Environmental Protection Agency and the
16

Illinois Power Agency shall be encouraged to be specific,
17

supported by data or other detailed analyses, and, if
18

objecting to all or a portion of the plan, accompanied by
19

specific alternative wording or proposals. All comments
20

shall be posted on the Environmental Protection Agency's,
21

the Illinois Power Agency's, and the Illinois Commerce
22

Commission's websites. Within 30 days following the end of
23

the 60-day review period, the Environmental Protection
24

Agency and the Illinois Power Agency shall revise the plan
25

as necessary based on the comments received and file its
26

revised plan with the Illinois Commerce Commission for

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1

approval.
2

(2) Within 60 days after the filing of the revised
3

plan at the Illinois Commerce Commission, any person
4

objecting to the plan shall file an objection with the
5

Illinois Commerce Commission. Within 30 days after the
6

expiration of the comment period, the Illinois Commerce
7

Commission shall determine whether an evidentiary hearing
8

is necessary. The Illinois Commerce Commission shall also
9

host 3 public hearings within 90 days after the plan is
10

filed. Following the evidentiary and public hearings, the
11

Illinois Commerce Commission shall enter its order
12

approving or approving with modifications the reliability
13

mitigation plan within 180 days.
14

(3) The Illinois Commerce Commission shall only
15

approve the plan if the Illinois Commerce Commission
16

determines that it will resolve the resource adequacy or
17

reliability deficiency identified in the reliability
18

mitigation plan at the least amount of CO
2
e and copollutant
19

emissions, taking into consideration the emissions impacts
20

on environmental justice communities, and that it will
21

ensure adequate, reliable, affordable, efficient, and
22

environmentally sustainable electric service at the lowest
23

total cost over time, taking into account the impact of
24

increases in emissions.
25

(4) If the resource adequacy or reliability deficiency
26

identified in the reliability mitigation plan is resolved

SB3929
- 76 -
LRB104 19036 BDA 32481 b
1

or reduced, the Environmental Protection Agency and the
2

Illinois Power Agency may file an amended plan adjusting
3

the reduction or delay in CO
2
e and copollutant emission
4

reduction requirements identified in the plan.
5
(Source: P.A. 104-458, eff. 6-1-26.)

6

Section 95.
No acceleration or delay.
Where this Act makes
7
changes in a statute that is represented in this Act by text
8
that is not yet or no longer in effect (for example, a Section
9
represented by multiple versions), the use of that text does
10
not accelerate or delay the taking effect of (i) the changes
11
made by this Act or (ii) provisions derived from any other
12
Public Act.

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