ELECTRIC TRANSMISSION SITING

Illinois General Assembly - Full Text of HB4995

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104TH GENERAL ASSEMBLY
State of Illinois
2025 and 2026
HB4995

Introduced , by Rep. Robyn Gabel

SYNOPSIS AS INTRODUCED:

See Index

Creates the Electric Transmission Facilities Siting Act. Defines
terms. Requires that, in the siting of new electric transmission
facilities, available corridors be used in the following order of
priority: (1) existing public utility corridors; (2) highway corridors;
and (3) new corridors. Provides that a public utility or developer may
construct, place, or maintain a high-voltage electric service line on a
public right-of-way or along a highway if (i) the public utility or
developer submits a colocation request for the high-voltage electric
service line to the Secretary of Transportation and (ii) the Secretary
reviews and approves the colocation request. Requires a public utility or
developer to develop a constructability report in consultation with the
Department of Transportation and requires the public utility or developer
and the Department to follow the terms and conditions of the
constructability report during the planning and approval process for the
siting of a high-voltage electric service line. Sets forth requirements
for the content of the constructability report. Amends the Public
Utilities Act. In provisions concerning distributed generation rebates,
provides that the owner or operator of distributed generation that, before
January 1, 2025 (rather than before the threshold date), is eligible for
net metering under the Act may apply for a base rebate for an associated
energy storage device behind the same retail customer meter as the
distributed generation, regardless of whether the distributed generation
applies for a rebate for the distributed generation device. Provides that,
after the threshold date, a stand-alone energy storage system that is
neither paired with distributed generation nor with any electric load
beyond the electric load that is used by the energy storage system itself
(rather than a stand-alone energy storage system) shall be compensated
with a rebate of $250 per kilowatt-hour of nameplate capacity. Amends the
Environmental Protection Act. In provisions concerning greenhouse gases,
provides that the Environmental Protection Agency and the Illinois Power
Agency shall file a plan to reduce or delay certain emissions reductions
requirements with the Illinois Commerce Commission for review in
conjunction with the integrated resource plan under certain provisions of
the Public Utilities Act. Makes other changes. Effective immediately.
LRB104 19660 AAS 33109 b

A BILL FOR

HB4995
LRB104 19660 AAS 33109 b
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 1.
Short title.
This Act may be cited as the
5
Electric Transmission Facilities Siting Act.

6

Section 5.
Definitions.
7

"Commission" means the Illinois Commerce Commission.
8

"Department" means the Illinois Department of
9
Transportation.
10

"Developer" means an individual, partnership, corporation,
11
or other entity seeking to build or maintain a high-voltage
12
electric service line.
13

"Electric transmission facilities" means electric
14
transmission lines, transmission towers, conductors,
15
insulators, foundations, grounding systems, access roads, and
16
any associated electric facilities, including transmission
17
substations.
18

"Highway" has the meaning given to that term in Section
19
2-202 of the Illinois Highway Code.
20

"High-voltage electric service line" means an electric
21
transmission line having a design voltage of 100,000 volts or
22
more.
23

"Secretary" means the Secretary of Transportation.

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"Public utility" has the meaning given to that term in
2
Section 3-105 of the Public Utilities Act.

3

Section 10.
Siting of electric transmission facilities.
4

(a) In the siting of new electric transmission facilities,
5
including high-voltage electric service lines, available
6
corridors shall be used in the following order of priority:
7

(1) Existing public utility corridors.
8

(2) Highway corridors.
9

(3) New corridors.
10

(b) Permitting on the corridors listed in subsection (a)
11
shall be done, to the greatest extent possible, in a manner
12
that accounts for economic and engineering considerations, the
13
reliability of the electric system, and the protection of the
14
environment.

15

Section 15.
High-voltage electric service line colocation
16
requests.
17

(a) A public utility or developer may construct, place, or
18
maintain a high-voltage electric service line on a public
19
right-of-way or along a highway if (i) the public utility or
20
developer submits to the Secretary a colocation request for
21
the high-voltage electric service line and (ii) the Secretary
22
reviews and approves the colocation request.
23

(b) The Secretary may deny a colocation request under this
24
Section if the Secretary determines that the construction,

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placement, or maintenance of a high-voltage electric service
2
line on a public right-of-way or along a highway would
3
endanger public safety or would interfere with the proper
4
function of the highway.
5

(c) If the Secretary denies a colocation request under
6
this Section, the Secretary shall submit the reasons for the
7
denial to the applicable public utility or developer and the
8
Commission within 90 days after the issuance of the denial.

9

Section 20.
High-voltage electric service line evaluation;
10
constructability report.
11

(a) A public utility or developer may submit a written
12
request to the Department for an evaluation of the corridors
13
described in subsection (a) of Section 10 for possible
14
locations for a high-voltage electric service line. Within 30
15
days after receipt of a written request under this subsection
16
(a), the Secretary shall assign a project coordinator to the
17
request. A project coordinator, upon assignment to a request,
18
shall begin the evaluation in coordination with the applicable
19
public utility or developer.
20

(b) The Department shall inform a public utility or
21
developer about any of the Department's current plans or
22
projects that could impact the public utility's or developer's
23
potential construction or placement of a high-voltage electric
24
service line within a corridor.
25

(c) After an evaluation under subsection (a) identifies an

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acceptable location within a corridor, a public utility or
2
developer, in consultation with the Department, shall develop
3
a constructability report. The constructability report shall
4
include (i) the terms and conditions for the siting of the
5
high-voltage electric service line and (ii) an agreed-upon
6
time frame during which the Department may not request the
7
relocation of the high-voltage electric service line. The
8
Department shall issue a permit to the public utility or
9
developer for the use of a public right-of-way within the
10
corridor for the siting of a high-voltage electric service
11
line only after a constructability report is approved by both
12
the Department and the public utility or developer.
13

(d) A public utility or developer and the Department shall
14
follow the terms and conditions of the approved
15
constructability report during the planning and approval
16
process for the siting of a high-voltage electric service
17
line. If the Department requires the relocation of a
18
high-voltage electric service line on a public right-of-way by
19
a specific date, the Department shall give the applicable
20
public utility or developer notice of the required relocation
21
no less than 10 years before the date of the required
22
relocation.
23

(e) If the Department requires the relocation of a
24
high-voltage electric service line during the prohibited time
25
frame specified in the constructability report or the
26
Department provides notice of the required relocation of a

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high-voltage electric service line to a public utility or
2
developer less than 10 years before the date of the required
3
relocation, the Department shall be responsible for 75% of the
4
costs incurred by the public utility or developer in the
5
relocation of the high-voltage electric service line.

6

Section 25.
The Public Utilities Act is amended by
7
changing Sections 16-107.6 and 16-107.9 as follows:

8

(220 ILCS 5/16-107.6)
9

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

Sec. 16-107.6.
Distributed generation rebate.
11

(a) In this Section:
12

"Additive services" means the services that distributed
13
energy resources provide to the energy system and society that
14
are not (1) already included in the base rebates for
15
system-wide grid services; or (2) otherwise already
16
compensated. Additive services may reflect, but shall not be
17
limited to, any geographic, time-based, performance-based, and
18
other benefits of distributed energy resources, as well as the
19
present and future technological capabilities of distributed
20
energy resources and present and future grid needs.
21

"Distributed energy resource" means a wide range of
22
technologies that are located on the customer side of the
23
customer's electric meter, including, but not limited to,
24
distributed generation, energy storage, electric vehicles, and

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demand response technologies.
2

"Energy storage system" means commercially available
3
technology that is capable of absorbing energy and storing it
4
for a period of time for use at a later time, including, but
5
not limited to, electrochemical, thermal, and
6
electromechanical technologies, and may be interconnected
7
behind the customer's meter or interconnected behind its own
8
meter.
9

"Smart inverter" means a device that converts direct
10
current into alternating current and meets the IEEE 1547-2018
11
equipment standards. Until devices that meet the IEEE
12
1547-2018 standard are available, devices that meet the UL
13
1741 SA standard are acceptable.
14

"Subscriber" has the meaning set forth in Section 1-10 of
15
the Illinois Power Agency Act.
16

"Subscription" has the meaning set forth in Section 1-10
17
of the Illinois Power Agency Act.
18

"System-wide grid services" means the benefits that a
19
distributed energy resource provides to the distribution grid
20
for a period of no less than 25 years. System-wide grid
21
services do not vary by location, time, or the performance
22
characteristics of the distributed energy resource.
23
System-wide grid services include, but are not limited to,
24
avoided or deferred distribution capacity costs, resilience
25
and reliability benefits, avoided or deferred distribution
26
operation and maintenance costs, distribution voltage and

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power quality benefits, and line loss reductions.
2

"Threshold date" means December 31, 2024 or the date on
3
which the utility's tariff or tariffs setting the new
4
compensation values established under subsection (e) take
5
effect, whichever is later.
6

(b) An electric utility that serves more than 200,000
7
customers in the State shall file a petition with the
8
Commission requesting approval of the utility's tariff to
9
provide a rebate to the owner or operator of distributed
10
generation, including third-party owned systems, that meets
11
the following criteria:
12

(1) has a nameplate generating capacity no greater
13

than 5,000 kilowatts and is primarily used to offset a
14

customer's electricity load;
15

(2) is located on the customer's side of the billing
16

meter and for the customer's own use;
17

(3) is interconnected to electric distribution
18

facilities owned by the electric utility under rules
19

adopted by the Commission by means of one or more
20

inverters or smart inverters required by this Section, as
21

applicable.
22

For purposes of this Section, "distributed generation"
23
shall satisfy the definition of distributed renewable energy
24
generation device set forth in Section 1-10 of the Illinois
25
Power Agency Act to the extent such definition is consistent
26
with the requirements of this Section.

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In addition, any new photovoltaic distributed generation
2
that is installed after June 1, 2017 (the effective date of
3
Public Act 99-906) must be installed by a qualified person, as
4
defined by subsection (i) of Section 1-56 of the Illinois
5
Power Agency Act.
6

The tariff shall include a base rebate that compensates
7
distributed generation for the system-wide grid services
8
associated with distributed generation and, after the
9
proceeding described in subsection (e) of this Section, an
10
additional payment or payments for the additive services. The
11
tariff shall provide that the smart inverter or smart
12
inverters associated with the distributed generation shall
13
provide autonomous response to grid conditions through its
14
default settings as approved by the Commission. Default
15
settings may not be changed after the execution of the
16
interconnection agreement except by mutual agreement between
17
the utility and the owner or operator of the distributed
18
generation. Nothing in this Section shall negate or supersede
19
Institute of Electrical and Electronics Engineers equipment
20
standards or other similar standards or requirements. The
21
tariff shall not limit the ability of the smart inverter or
22
smart inverters or other distributed energy resource to
23
provide wholesale market products such as regulation, demand
24
response, or other services, or limit the ability of the owner
25
of the smart inverter or the other distributed energy resource
26
to receive compensation for providing those wholesale market

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LRB104 19660 AAS 33109 b
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products or services.
2

(b-5) Within 30 days after the effective date of this
3
amendatory Act of the 102nd General Assembly, each electric
4
public utility with 3,000,000 or more retail customers shall
5
file a tariff with the Commission that further compensates any
6
retail customer that installs or has installed photovoltaic
7
facilities paired with energy storage facilities on or
8
adjacent to its premises for the benefits the facilities
9
provide to the distribution grid. The tariff shall provide
10
that, in addition to the other rebates identified in this
11
Section, the electric utility shall rebate to such retail
12
customer (i) the previously incurred and future costs of
13
installing interconnection facilities and related
14
infrastructure to enable full participation in the PJM
15
Interconnection, LLC or its successor organization frequency
16
regulation market; and (ii) all wholesale demand charges
17
incurred after the effective date of this amendatory Act of
18
the 102nd General Assembly. The Commission shall approve, or
19
approve with modification, the tariff within 120 days after
20
the utility's filing.
21

(c) The proposed tariff authorized by subsection (b) of
22
this Section shall include the following participation terms
23
for rebates to be applied under this Section for distributed
24
generation that satisfies the criteria set forth in subsection
25
(b) of this Section:
26

(1) The owner or operator of distributed generation

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that services customers not eligible for net metering
2

under subsection (d), (d-5), or (e) of Section 16-107.5 of
3

this Act may apply for a rebate as provided for in this
4

Section. Until the threshold date, the value of the rebate
5

shall be $250 per kilowatt of nameplate generating
6

capacity, measured as nominal DC power output, of that
7

customer's distributed generation. To the extent the
8

distributed generation also has an associated energy
9

storage, then the energy storage system shall be
10

separately compensated with a base rebate of $250 per
11

kilowatt-hour of nameplate capacity. Any distributed
12

generation device that is compensated for storage in this
13

subsection (1) before the threshold date shall participate
14

in one or more programs determined through the Multi-Year
15

Integrated Grid Planning process that are designed to meet
16

peak reduction and flexibility. After the threshold date,
17

the value of the base rebate and additional compensation
18

for any additive services shall be as determined by the
19

Commission in the proceeding described in subsection (e)
20

of this Section, provided that the value of the base
21

rebate for system-wide grid services shall not be lower
22

than $250 per kilowatt of nameplate generating capacity of
23

distributed generation or community renewable generation
24

project.
25

(2) The owner or operator of distributed generation
26

that, before the threshold date, would have been eligible

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for net metering under subsection (d), (d-5), or (e) of
2

Section 16-107.5 of this Act and that has not previously
3

received a distributed generation rebate, may apply for a
4

rebate as provided for in this Section. Until the
5

threshold date, the value of the base rebate shall be $300
6

per kilowatt of nameplate generating capacity, measured as
7

nominal DC power output, of the distributed generation.
8

The owner or operator of distributed generation that,
9

before the threshold date, is eligible for net metering
10

under subsection (d), (d-5), or (e) of Section 16-107.5 of
11

this Act may apply for a base rebate for an associated
12

energy storage device behind the same retail customer
13

meter as the distributed generation, regardless of whether
14

the distributed generation applies for a rebate for the
15

distributed generation device. The energy storage system
16

shall be separately compensated at a base payment of $300
17

per kilowatt-hour of nameplate capacity. Any distributed
18

generation device that is compensated for storage in this
19

subsection (2) before the threshold date shall participate
20

in a peak time rebate program, hourly pricing program, or
21

time-of-use rate program offered by the applicable
22

electric utility. After the threshold date, the value of
23

the base rebate and additional compensation for any
24

additive services shall be as determined by the Commission
25

in the proceeding described in subsection (e) of this
26

Section, provided that, prior to December 31, 2029, the

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value of the base rebate for system-wide services shall
2

not be lower than $300 per kilowatt of nameplate
3

generating capacity of distributed generation, after which
4

it shall not be lower than $250 per kilowatt of nameplate
5

capacity. The eligibility of energy storage devices that
6

are interconnected behind the same retail customer meter
7

as the distributed generation shall not be limited to
8

energy storage devices interconnected after the effective
9

date of this amendatory Act of the 103rd General Assembly.
10

To the extent that an electric utility's tariffs are
11

inconsistent with the requirements of this paragraph (2)
12

as modified by this amendatory Act of the 103rd General
13

Assembly, such electric utility shall, within 30 days,
14

file modified tariffs consistent with the requirements of
15

this paragraph (2).
16

(3) Upon approval of a rebate application submitted
17

under this subsection (c), the retail customer shall no
18

longer be entitled to receive any delivery service credits
19

for the excess electricity generated by its facility and
20

shall be subject to the provisions of subsection (n) of
21

Section 16-107.5 of this Act unless the owner or operator
22

receives a rebate only for an energy storage device and
23

not for the distributed generation device.
24

(4) To be eligible for a rebate described in this
25

subsection (c), the owner or operator of the distributed
26

generation must have a smart inverter installed and in

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operation on the distributed generation.
2

(d) The Commission shall review the proposed tariff
3
authorized by subsection (b) of this Section and may make
4
changes to the tariff that are consistent with this Section
5
and with the Commission's authority under Article IX of this
6
Act, subject to notice and hearing. Following notice and
7
hearing, the Commission shall issue an order approving, or
8
approving with modification, such tariff no later than 240
9
days after the utility files its tariff. Upon the effective
10
date of this amendatory Act of the 102nd General Assembly, an
11
electric utility shall file a petition with the Commission to
12
amend and update any existing tariffs to comply with
13
subsections (b) and (c).
14

(e) By no later than June 30, 2023, the Commission shall
15
open an independent, statewide investigation into the value
16
of, and compensation for, distributed energy resources. The
17
Commission shall conduct the investigation, but may arrange
18
for experts or consultants independent of the utilities and
19
selected by the Commission to assist with the investigation.
20
The cost of the investigation shall be shared by the utilities
21
filing tariffs under subsection (b) of this Section but may be
22
recovered as an expense through normal ratemaking procedures.
23

(1) The Commission shall ensure that the investigation
24

includes, at minimum, diverse sets of stakeholders; a
25

review of best practices in calculating the value of
26

distributed energy resource benefits; a review of the full

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value of the distributed energy resources and the manner
2

in which each component of that value is or is not
3

otherwise compensated; and assessments of how the value of
4

distributed energy resources may evolve based on the
5

present and future technological capabilities of
6

distributed energy resources and based on present and
7

future grid needs.
8

(2) The Commission's final order concluding this
9

investigation shall establish an annual process and
10

formula for the compensation of distributed generation and
11

energy storage systems, and an initial set of inputs for
12

that formula. The Commission's final order concluding this
13

investigation shall establish base rebates that compensate
14

distributed generation, community renewable generation
15

projects and energy storage systems for the system-wide
16

grid services that they provide. Those base rebate values
17

shall be consistent across the state, and shall not vary
18

by customer, customer class, customer location, or any
19

other variable. With respect to rebates for distributed
20

generation or community renewable generation projects,
21

that rebate shall not be lower than $250 per kilowatt of
22

nameplate generating capacity of the distributed
23

generation or community renewable generation project. The
24

Commission's final order concluding this proceeding shall
25

also direct the utilities to update the formula, on an
26

annual basis, with inputs derived from their integrated

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grid plans developed pursuant to Section 16-105.17. The
2

base rebate shall be updated annually based on the annual
3

updates to the formula inputs, but, with respect to
4

rebates for distributed generation or community renewable
5

generation projects, shall be no lower than $250 per
6

kilowatt of nameplate generating capacity of the
7

distributed generation or community renewable generation
8

project.
9

(3) The Commission shall also determine, as a part of
10

its investigation under this subsection, whether
11

distributed energy resources can provide any additive
12

services. Those additive services may include services
13

that are provided through utility-controlled responses to
14

grid conditions. If the Commission determines that
15

distributed energy resources can provide additive grid
16

services, the Commission shall determine the terms and
17

conditions for the operation and compensation of those
18

services. That compensation shall be above and beyond the
19

base rebate that the distributed energy generation,
20

community renewable generation project and energy storage
21

system receives. Compensation for additive services may
22

vary by location, time, performance characteristics,
23

technology types, or other variables.
24

(4) The Commission shall ensure that compensation for
25

distributed energy resources, including base rebates and
26

any payments for additive services, shall reflect all

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reasonably known and measurable values of the distributed
2

generation over its full expected useful life.
3

Compensation for additive services shall reflect, but
4

shall not be limited to, any geographic, time-based,
5

performance-based, and other benefits of distributed
6

generation, as well as the present and future
7

technological capabilities of distributed energy resources
8

and present and future grid needs.
9

(5) The Commission shall consider the electric
10

utility's integrated grid plan developed pursuant to
11

Section 16-105.17 of this Act to help identify the value
12

of distributed energy resources for the purpose of
13

calculating the compensation described in this subsection.
14

(6) The Commission shall determine additional
15

compensation for distributed energy resources that creates
16

savings and value on the distribution system by being
17

co-located or in close proximity to electric vehicle
18

charging infrastructure in use by medium-duty and
19

heavy-duty vehicles, primarily serving environmental
20

justice communities, as outlined in the utility integrated
21

grid planning process under Section 16-105.17 of this Act.
22

No later than 60 days after the Commission enters its
23
final order under this subsection (e), each utility shall file
24
its updated tariff or tariffs in compliance with the order,
25
including new tariffs for the recovery of costs incurred under
26
this subsection (e) that shall provide for volumetric-based

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cost recovery, and the Commission shall approve, or approve
2
with modification, the tariff or tariffs within 240 days after
3
the utility's filing.
4

(f) Notwithstanding any provision of this Act to the
5
contrary, the owner or operator of a community renewable
6
generation project as defined in Section 1-10 of the Illinois
7
Power Agency Act shall also be eligible to apply for the rebate
8
described in this Section. The owner or operator of the
9
community renewable generation project may apply for a rebate
10
only if the owner or operator, or previous owner or operator,
11
of the community renewable generation project has not already
12
submitted an application, and, regardless of whether the
13
subscriber is a residential or non-residential customer, may
14
be allowed the amount identified in paragraph (1) of
15
subsection (c) applicable on the date that the application is
16
submitted.
17

(g) The owner of the distributed generation or community
18
renewable generation project may apply for the rebate or
19
rebates approved under this Section at the time of execution
20
of an interconnection agreement with the distribution utility
21
and shall receive the value available at that time of
22
execution of the interconnection agreement, provided the
23
project reaches mechanical completion within 24 months after
24
execution of the interconnection agreement. If the project has
25
not reached mechanical completion within 24 months after
26
execution, the owner may reapply for the rebate or rebates

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approved under this Section available at the time of
2
application and shall receive the value available at the time
3
of application. The utility shall issue the rebate no later
4
than 60 days after the project is energized. In the event the
5
application is incomplete or the utility is otherwise unable
6
to calculate the payment based on the information provided by
7
the owner, the utility shall issue the payment no later than 60
8
days after the application is complete or all requested
9
information is received.
10

(h) An electric utility shall recover from its retail
11
customers all of the costs of the rebates made under a tariff
12
or tariffs approved under subsection (d) of this Section,
13
including, but not limited to, the value of the rebates and all
14
costs incurred by the utility to comply with and implement
15
subsections (b) and (c) of this Section, but not including
16
costs incurred by the utility to comply with and implement
17
subsection (e) of this Section, consistent with the following
18
provisions:
19

(1) The utility shall defer the full amount of its
20

costs as a regulatory asset. The total costs deferred as a
21

regulatory asset shall be amortized over a 15-year period.
22

The unamortized balance shall be recognized as of December
23

31 for a given year. The utility shall also earn a return
24

on the total of the unamortized balance of the regulatory
25

assets, less any deferred taxes related to the unamortized
26

balance, at an annual rate equal to the utility's weighted

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average cost of capital that includes, based on a year-end
2

capital structure, the utility's actual cost of debt for
3

the applicable calendar year and a cost of equity, which
4

shall be calculated as the sum of (i) the average for the
5

applicable calendar year of the monthly average yields of
6

30-year U.S. Treasury bonds published by the Board of
7

Governors of the Federal Reserve System in its weekly H.15
8

Statistical Release or successor publication; and (ii) 580
9

basis points, including a revenue conversion factor
10

calculated to recover or refund all additional income
11

taxes that may be payable or receivable as a result of that
12

return.
13

When an electric utility creates a regulatory asset
14

under the provisions of this paragraph (1) of subsection
15

(h), the costs are recovered over a period during which
16

customers also receive a benefit, which is in the public
17

interest. Accordingly, it is the intent of the General
18

Assembly that an electric utility that elects to create a
19

regulatory asset under the provisions of this paragraph
20

(1) shall recover all of the associated costs, including,
21

but not limited to, its cost of capital as set forth in
22

this paragraph (1). After the Commission has approved the
23

prudence and reasonableness of the costs that comprise the
24

regulatory asset, the electric utility shall be permitted
25

to recover all such costs, and the value and
26

recoverability through rates of the associated regulatory

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asset shall not be limited, altered, impaired, or reduced.
2

To enable the financing of the incremental capital
3

expenditures, including regulatory assets, for electric
4

utilities that serve less than 3,000,000 retail customers
5

but more than 500,000 retail customers in the State, the
6

utility's actual year-end capital structure that includes
7

a common equity ratio, excluding goodwill, of up to and
8

including 50% of the total capital structure shall be
9

deemed reasonable and used to set rates.
10

(2) The utility, at its election, may recover all of
11

the costs as part of a filing for a general increase in
12

rates under Article IX of this Act, as part of an annual
13

filing to update a performance-based formula rate under
14

subsection (d) of Section 16-108.5 of this Act, or through
15

an automatic adjustment clause tariff, provided that
16

nothing in this paragraph (2) permits the double recovery
17

of such costs from customers. If the utility elects to
18

recover the costs it incurs under subsections (b) and (c)
19

through an automatic adjustment clause tariff, the utility
20

may file its proposed tariff together with the tariff it
21

files under subsection (b) of this Section or at a later
22

time. The proposed tariff shall provide for an annual
23

reconciliation, less any deferred taxes related to the
24

reconciliation, with interest at an annual rate of return
25

equal to the utility's weighted average cost of capital as
26

calculated under paragraph (1) of this subsection (h),

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including a revenue conversion factor calculated to
2

recover or refund all additional income taxes that may be
3

payable or receivable as a result of that return, of the
4

revenue requirement reflected in rates for each calendar
5

year, beginning with the calendar year in which the
6

utility files its automatic adjustment clause tariff under
7

this subsection (h), with what the revenue requirement
8

would have been had the actual cost information for the
9

applicable calendar year been available at the filing
10

date. The Commission shall review the proposed tariff and
11

may make changes to the tariff that are consistent with
12

this Section and with the Commission's authority under
13

Article IX of this Act, subject to notice and hearing.
14

Following notice and hearing, the Commission shall issue
15

an order approving, or approving with modification, such
16

tariff no later than 240 days after the utility files its
17

tariff.
18

(i) An electric utility shall recover from its retail
19
customers, on a volumetric basis, all of the costs of the
20
rebates made under a tariff or tariffs placed into effect
21
under subsection (e) of this Section, including, but not
22
limited to, the value of the rebates and all costs incurred by
23
the utility to comply with and implement subsection (e) of
24
this Section, consistent with the following provisions:
25

(1) The utility may defer a portion of its costs as a
26

regulatory asset. The Commission shall determine the

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portion that may be appropriately deferred as a regulatory
2

asset. Factors that the Commission shall consider in
3

determining the portion of costs that shall be deferred as
4

a regulatory asset include, but are not limited to: (i)
5

whether and the extent to which a cost effectively
6

deferred or avoided other distribution system operating
7

costs or capital expenditures; (ii) the extent to which a
8

cost provides environmental benefits; (iii) the extent to
9

which a cost improves system reliability or resilience;
10

(iv) the electric utility's distribution system plan
11

developed pursuant to Section 16-105.17 of this Act; (v)
12

the extent to which a cost advances equity principles; and
13

(vi) such other factors as the Commission deems
14

appropriate. The remainder of costs shall be deemed an
15

operating expense and shall be recoverable if found
16

prudent and reasonable by the Commission.
17

The total costs deferred as a regulatory asset shall
18

be amortized over a 15-year period. The unamortized
19

balance shall be recognized as of December 31 for a given
20

year. The utility shall also earn a return on the total of
21

the unamortized balance of the regulatory assets, less any
22

deferred taxes related to the unamortized balance, at an
23

annual rate equal to the utility's weighted average cost
24

of capital that includes, based on a year-end capital
25

structure, the utility's actual cost of debt for the
26

applicable calendar year and a cost of equity, which shall

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be calculated as the sum of: (I) the average for the
2

applicable calendar year of the monthly average yields of
3

30-year U.S. Treasury bonds published by the Board of
4

Governors of the Federal Reserve System in its weekly H.15
5

Statistical Release or successor publication; and (II) 580
6

basis points, including a revenue conversion factor
7

calculated to recover or refund all additional income
8

taxes that may be payable or receivable as a result of that
9

return.
10

(2) The utility may recover all of the costs through
11

an automatic adjustment clause tariff, on a volumetric
12

basis. The utility may file its proposed cost-recovery
13

tariff together with the tariff it files under subsection
14

(e) of this Section or at a later time. The proposed tariff
15

shall provide for an annual reconciliation, less any
16

deferred taxes related to the reconciliation, with
17

interest at an annual rate of return equal to the
18

utility's weighted average cost of capital as calculated
19

under paragraph (1) of this subsection (i), including a
20

revenue conversion factor calculated to recover or refund
21

all additional income taxes that may be payable or
22

receivable as a result of that return, of the revenue
23

requirement reflected in rates for each calendar year,
24

beginning with the calendar year in which the utility
25

files its automatic adjustment clause tariff under this
26

subsection (i), with what the revenue requirement would

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have been had the actual cost information for the
2

applicable calendar year been available at the filing
3

date. The Commission shall review the proposed tariff and
4

may make changes to the tariff that are consistent with
5

this Section and with the Commission's authority under
6

Article IX of this Act, subject to notice and hearing.
7

Following notice and hearing, the Commission shall issue
8

an order approving, or approving with modification, such
9

tariff no later than 240 days after the utility files its
10

tariff.
11

(j) No later than 90 days after the Commission enters an
12
order, or order on rehearing, whichever is later, approving an
13
electric utility's proposed tariff under this Section, the
14
electric utility shall provide notice of the availability of
15
rebates under this Section.
16
(Source: P.A. 102-662, eff. 9-15-21; 102-1031, eff. 5-27-22;
17
103-1066, eff. 2-20-25.)

18

(Text of Section after amendment by P.A. 104-458
)
19

Sec. 16-107.6.
Distributed generation and storage rebate.
20

(a) In this Section:
21

"Additive services" means the services that distributed
22
energy resources provide to the energy system and society that
23
are described in Section 16-107.9.
24

"Distributed energy resource" means a wide range of
25
technologies that are located on the customer side of the

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customer's electric meter, including, but not limited to,
2
distributed generation, energy storage, electric vehicles, and
3
demand response technologies.
4

"Distributed storage" means energy storage systems that
5
are interconnected behind the customer's meter to the
6
distribution system or interconnected behind the storage
7
system's own meter to the distribution system.
8

"Energy storage system" means commercially available
9
technology that is capable of absorbing energy and storing it
10
for a period of time for use at a later time, including, but
11
not limited to, electrochemical, thermal, and
12
electromechanical technologies, and may be interconnected
13
behind the customer's meter or interconnected behind its own
14
meter.
15

"Smart inverter" means a device that converts direct
16
current into alternating current and meets the IEEE 1547-2018
17
equipment standards. Until devices that meet the IEEE
18
1547-2018 standard are available, devices that meet the UL
19
1741 SA standard are acceptable.
20

"Stand-alone energy storage system" means an energy
21
storage system that (i) is not paired with distributed
22
generation and (ii) has a nameplate capacity no greater than
23
5,000 kilowatt.

24

"Subscriber" has the meaning set forth in Section 1-10 of
25
the Illinois Power Agency Act.
26

"Subscription" has the meaning set forth in Section 1-10

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1
of the Illinois Power Agency Act.
2

"System-wide grid services" means the benefits that a
3
distributed energy resource provides to the distribution grid
4
for a period of no less than 25 years. System-wide grid
5
services do not vary by location, time, or the performance
6
characteristics of the distributed energy resource.
7
System-wide grid services include, but are not limited to,
8
avoided or deferred distribution capacity costs, resilience
9
and reliability benefits, avoided or deferred distribution
10
operation and maintenance costs, distribution voltage and
11
power quality benefits, and line loss reductions.
12

"Threshold date" means the date 2 years after the
13
effective date of this amendatory Act of the 104th General
14
Assembly or the date on which the utility's tariff or tariffs
15
authorized by Section 16-107.9 take effect, whichever is
16
later.
17

(b) An electric utility that serves more than 200,000
18
customers in the State shall file a petition with the
19
Commission requesting approval of the utility's tariff to
20
provide a rebate to the owner or operator of distributed
21
generation
or distributed storage
, including third-party owned
22
systems, that meets the following criteria:
23

(1) has a nameplate
generating
capacity no greater
24

than 5,000 kilowatts and is primarily used to offset a
25

customer's electricity load, or as otherwise as defined
26

for community renewable generation projects in Section

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1

1-10 of the Illinois Power Agency Act;
2

(2) is located on the customer's side of the billing
3

meter and for the customer's own use;
4

(3) is interconnected to electric distribution
5

facilities owned by the electric utility under rules
6

adopted by the Commission by means of one or more
7

inverters or smart inverters required by this Section, as
8

applicable.
9

For purposes of this Section, "distributed generation"
10
shall satisfy the definition of distributed renewable energy
11
generation device set forth in Section 1-10 of the Illinois
12
Power Agency Act to the extent such definition is consistent
13
with the requirements of this Section.
14

In addition, any new photovoltaic distributed generation
15
that is installed after June 1, 2017 (the effective date of
16
Public Act 99-906) must be installed by a qualified person, as
17
defined by subsection (i) of Section 1-56 of the Illinois
18
Power Agency Act.
19

The tariff shall include a base rebate that compensates
20
distributed generation for the system-wide grid services
21
associated with distributed generation and an additional
22
payment or payments for any additive services identified by
23
the Commission under Section 16-107.9. The distributed
24
generation and storage tariff shall provide that the smart
25
inverter or smart inverters associated with the distributed
26
generation shall provide autonomous response to grid

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1
conditions through its default settings as approved by the
2
Commission. Default settings may not be changed after the
3
execution of the interconnection agreement except by mutual
4
agreement between the utility and the owner or operator of the
5
distributed generation. Nothing in this Section shall negate
6
or supersede Institute of Electrical and Electronics Engineers
7
equipment standards or other similar standards or
8
requirements. The tariff shall not limit the ability of the
9
smart inverter or smart inverters or other distributed energy
10
resource to provide wholesale market products such as
11
regulation, demand response, or other services, or limit the
12
ability of the owner of the smart inverter or the other
13
distributed energy resource to receive compensation for
14
providing those wholesale market products or services.
15

(b-5) Within 30 days after the effective date of this
16
amendatory Act of the 102nd General Assembly, each electric
17
public utility with 3,000,000 or more retail customers shall
18
file a tariff with the Commission that further compensates any
19
retail customer that installs or has installed photovoltaic
20
facilities paired with energy storage facilities on or
21
adjacent to its premises for the benefits the facilities
22
provide to the distribution grid. The tariff shall provide
23
that, in addition to the other rebates identified in this
24
Section, the electric utility shall rebate to such retail
25
customer (i) the previously incurred and future costs of
26
installing interconnection facilities and related

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1
infrastructure to enable full participation in the PJM
2
Interconnection, LLC or its successor organization frequency
3
regulation market; and (ii) all wholesale demand charges
4
incurred after the effective date of this amendatory Act of
5
the 102nd General Assembly. The Commission shall approve, or
6
approve with modification, the tariff within 120 days after
7
the utility's filing.
8

To be eligible for a rebate described in this subsection
9
(b-5), the owner or operator of the distributed generation
10
shall provide proof of participation in the frequency
11
regulation market. Upon providing proof of participation, the
12
retail customer shall be entitled to a rebate equal to the cost
13
of the interconnection facilities paid to ComEd, regardless of
14
whether the retail customer would have incurred the
15
interconnection costs in the absence of participating in the
16
frequency regulation market, plus the cost of software,
17
telecommunications hardware, and telemetry paid to enable
18
communication with PJM for purposes of participating in the
19
frequency regulation market. A utility providing rebates
20
described in this subsection (b-5) shall be entitled to
21
recover the costs of the rebates as provided for in subsection
22
(h) of this Section. To the extent the electric utility's
23
tariff is modified to comply with this subsection (b-5), it
24
shall file a revised tariff with the Commission within 120
25
days after the effective date of this amendatory Act of the
26
104th General Assembly, and the Commission shall approve, or

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1
approve with modification, the tariff within 240 days after
2
the Commission initiates the docket.
3

(c) The proposed tariff authorized by subsection (b) of
4
this Section shall include the following participation terms
5
for rebates to be applied under this Section for distributed
6
generation that satisfies the criteria set forth in subsection
7
(b) of this Section:
8

(1) The owner or operator of distributed generation or
9

distributed storage that services customers not eligible
10

for net metering under subsection (d), (d-5), or (e) of
11

Section 16-107.5 of this Act may apply for a rebate as
12

provided for in this Section. The value of the rebate
13

shall be $250 per kilowatt of nameplate generating
14

capacity, measured as nominal DC power output, of that
15

customer's distributed generation. To the extent the
16

distributed generation also has an associated energy
17

storage, then until the threshold date for systems other
18

than community renewable generation projects paired with
19

an energy storage system, the energy storage system shall
20

be separately compensated with a rebate of $250 per
21

kilowatt-hour of nameplate capacity. To the extent that a
22

community renewable generation project is paired with an
23

energy storage system or an energy storage system that is
24

paired with distributed generation, the energy storage
25

system shall be separately compensated with a rebate of
26

$250 per kilowatt-hour of nameplate capacity. A

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stand-alone energy storage system shall be compensated
2

with a rebate of $250 per kilowatt-hour of nameplate
3

capacity. Any distributed generation device that is
4

compensated for storage in this subsection (1) after the
5

effective date of this amendatory Act of the 104th General
6

Assembly shall participate in one or more programs
7

authorized by paragraph (1) of subsection (e).
8

Compensation for any additive services shall be as
9

determined by the Commission in the proceeding described
10

in Section 16-107.9. To the extent that an electric
11

utility's tariffs are inconsistent with the requirements
12

of this paragraph (1) as modified by this amendatory Act
13

of the 104th General Assembly, the electric utility shall,
14

within 60 days after the effective date of this amendatory
15

Act of the 104th General Assembly, file modified tariffs
16

consistent with the requirements of this paragraph (1). If
17

the Commission chooses to suspend the modified tariffs
18

following notice and hearing, the Commission shall issue
19

an order approving, or approving with modification, the
20

modified tariffs no later than 90 days after the
21

Commission initiates the docket.
22

(2) The owner or operator of distributed generation
23

that, before
January 1, 2025

the threshold date
, would
24

have been eligible for net metering under subsection (d),
25

(d-5), or (e) of Section 16-107.5 of this Act and that has
26

not previously received a distributed generation rebate,

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1

may apply for a rebate as provided for in this Section.
2

Until December 31, 2029, the value of the base rebate
3

shall be $300 per kilowatt of nameplate generating
4

capacity, measured as nominal DC power output, of the
5

distributed generation. On or after January 1, 2030, the
6

value of the base rebate shall be $250 per kilowatt of
7

nameplate generating capacity, measured as nominal DC
8

power output, of the distributed generation. The owner or
9

operator of distributed generation that, before
January 1,
10

2025

the threshold date
, is eligible for net metering
11

under subsection (d), (d-5), or (e) of Section 16-107.5 of
12

this Act may apply for a base rebate for an associated
13

energy storage device behind the same retail customer
14

meter as the distributed generation, regardless of whether
15

the distributed generation applies for a rebate for the
16

distributed generation device. An energy storage system,
17

whether or not paired with distributed generation, shall
18

be separately compensated at a base payment of $300 per
19

kilowatt-hour of nameplate capacity until the threshold
20

date. After the threshold date, a stand-alone energy
21

storage system
that is neither paired with distributed
22

generation nor with any electric load beyond the electric
23

load that is used by the energy storage system itself

24

shall be compensated with a rebate of $250 per
25

kilowatt-hour of nameplate capacity. Any distributed
26

generation device that is compensated for storage in this

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1

subsection (2) has the option to participate in either an
2

hourly pricing program or time-of-use rate program and any
3

distributed generation device that is compensated for
4

storage in this subsection (2) after the effective date of
5

this amendatory Act of the 104th General Assembly shall
6

participate in a scheduled dispatch program set forth in
7

paragraph (1) of subsection (e) when it becomes available.
8

Compensation for any additive services or other programs
9

shall be as determined by the Commission in the proceeding
10

described in Section 16-107.9. To the extent that an
11

electric utility's tariffs are inconsistent with the
12

requirements of this paragraph (2) as modified by this
13

amendatory Act of the 104th General Assembly, such
14

electric utility shall, within 60 days, file modified
15

tariffs consistent with the requirements of this paragraph
16

(2).
17

(3) Upon approval of a rebate application submitted
18

under this subsection (c), the retail customer shall no
19

longer be entitled to receive any delivery service credits
20

for the excess electricity generated by its facility and
21

shall be subject to the provisions of subsection (n) of
22

Section 16-107.5 of this Act unless the owner or operator
23

receives a rebate only for an energy storage device and
24

not for the distributed generation device.
25

(4) To be eligible for a rebate described in this
26

subsection (c), the owner or operator of the distributed

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1

generation must have a smart inverter installed and in
2

operation on the distributed generation.
3

(5) The owner or operator of any distributed
4

generation or distributed storage system whose electric
5

service has not been declared competitive under Section
6

16-113 as of July 1, 2011 or the owner or operator of a
7

community renewable generation project participating in
8

the Adjustable Block Program as a community-driven
9

community solar project as defined in item (v) of
10

subparagraph (K) of paragraph (1) of subsection (c) of
11

Section 1-75 of the Illinois Power Agency Act and that has
12

an interconnection agreement dated after the effective
13

date of this amendatory Act of the 104th General Assembly
14

shall be eligible for an additional payment or payments to
15

the applicable rebate under paragraphs (1) or (2) of this
16

subsection (c) in an amount set by tariff and approved by
17

the Commission if located in an equity investment eligible
18

community, as defined in Section 1-10 of the Illinois
19

Power Agency Act, at the time the interconnection
20

agreement is signed.
21

(d) The Commission shall review the proposed tariff
22
authorized by subsection (b) of this Section and may make
23
changes to the tariff that are consistent with this Section
24
and with the Commission's authority under Article IX of this
25
Act, subject to notice and hearing. Following notice and
26
hearing, the Commission shall issue an order approving, or

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1
approving with modification, such tariff no later than 240
2
days after the utility files its tariff. Upon the effective
3
date of this amendatory Act of the 102nd General Assembly, an
4
electric utility shall file a petition with the Commission to
5
amend and update any existing tariffs to comply with
6
subsections (b) and (c).
7

(e) By no later than June 30, 2026, the Commission shall
8
establish a scheduled dispatch virtual power plant program in
9
which customers that own or operate an energy storage system
10
that receive a rebate for the distributed storage portion
11
under paragraphs (1) and (2) of subsection (c) are required to
12
participate.
13

(1) The scheduled dispatch virtual power plant program
14

shall require an enrollment period of 5 years and require
15

each participating system to commit to dispatch each
16

weekday during the months of June, July, August, and
17

September from 4 p.m. to 6 p.m. for systems interconnected
18

behind the meter of a retail customer and from 4 p.m. to 7
19

p.m. for systems interconnected on the distribution system
20

of an electric utility and not behind the meter of a retail
21

customer. For stand-alone storage
that is neither paired
22

with distributed generation nor with any electric load
23

beyond the electric load that is used by the energy
24

storage system itself
, commitments to dispatch shall be
25

voluntary. Upon petition by the applicable electric
26

utility or on its own motion, the Commission may approve

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1

different dispatch schedules provided that dispatch events
2

do not exceed 80 days and shall not exceed 2 hours for
3

systems interconnected behind the meter of a retail
4

customer or 3 hours for systems interconnected on the
5

distribution system of an electric utility and not behind
6

the meter of a retail customer.
7

(2) The scheduled dispatch virtual power plant program
8

shall be open to all customer classes with eligible
9

distributed energy resources and shall measure performance
10

based on combined export of paired resources if the
11

eligible device is inverter-based renewables paired with
12

storage through at least December 31, 2030 and until the
13

Commission approves and the utility implements a tariff
14

under subsection (d) of Section 16-107.9 of this Act, at
15

which time such customers shall be transitioned to that
16

tariff in a manner prescribed in the tariff. The scheduled
17

dispatch virtual power plant program shall be required for
18

all community renewable generation projects paired with
19

distributed energy resources without regard to the
20

threshold date.
21

(3) Compensation shall be set by the Commission but
22

shall not be less than $10 per kilowatt of average
23

dispatch during identified hours, paid to enrolled
24

customers or project owners at end of program year. For
25

distributed generation interconnected to an electric
26

utility's distribution system and not behind the meter of

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a retail customer, dispatch to determine compensation
2

shall be measured at point of interconnection. For
3

distributed generation and storage interconnected behind
4

the meter of a retail customer, dispatch to determine
5

compensation shall be measured at the inverter connected
6

to the storage device.
7

(4) No later than June 1, 2026, each public utility
8

shall file an initial scheduled dispatch virtual power
9

plant tariff. The Commission shall approve, or approve
10

with modifications, the initial scheduled dispatch virtual
11

power plant tariff for each utility not later than June
12

30, 2026.
13

(5) The Commission, by its own motion or by petition
14

by an electric utility, may establish other additive
15

services programs in addition to the virtual power plant
16

program under Section 16-107.9. Nothing in this Section is
17

intended to preempt or delay the implementation of other
18

utility programs for devices that are not a part of the
19

scheduled dispatch virtual power plant program that the
20

Commission or utility may propose or require.
21

(6) No later than December 31, 2028, the utilities
22

shall file with the Commission a report that includes
23

information on the following: (A) the number of
24

participants in the scheduled dispatch program; (B)
25

impacts to energy supply prices and wholesale market
26

activities; (C) impacts on distribution system investments

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and planning; and (D) any potential pathways by which the
2

virtual power plan program described in Section 16-107.9
3

may be designed to capture wholesale market value through
4

participation in the wholesale market and apply that
5

wholesale market revenue to reduce utility distribution or
6

electric supply rates for customers.
7

(f) Notwithstanding any provision of this Act to the
8
contrary, the owner or operator of a community renewable
9
generation project as defined in Section 1-10 of the Illinois
10
Power Agency Act whether or not a paired energy storage system
11
or the owner or operator of an energy storage system that is
12
eligible for net metering under subsection (l-10) of Section
13
16-107.5 shall also be eligible to apply for the rebate
14
described in this Section. The owner or operator of the
15
community renewable generation project whether or not a paired
16
energy storage system or the owner or operator of an energy
17
storage system that is eligible for net metering under
18
subsection (l-10) of Section 16-107.5 may apply for a rebate
19
only if the owner or operator, or previous owner or operator,
20
of the community renewable generation project whether or not a
21
paired energy storage system or the owner or operator of an
22
energy storage system that is eligible for net metering under
23
subsection (l-10) of Section 16-107.5 has not already
24
submitted an application, and, regardless of whether the
25
subscriber is a residential or non-residential customer, may
26
be allowed the amount identified in paragraph (1) of

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subsection (c) applicable on the date that the application is
2
submitted.
3

(g) The owner of a distributed storage system, whether or
4
not paired with distributed generation, may apply for the
5
rebate or rebates approved under this Section at the time of
6
execution of an interconnection agreement with the
7
distribution utility and shall receive the value available at
8
that time of execution of the interconnection agreement. The
9
utility shall issue the rebate no later than 60 days after the
10
project is energized. In the event the application is
11
incomplete or the utility is otherwise unable to calculate the
12
payment based on the information provided by the owner, the
13
utility shall issue the payment no later than 60 days after the
14
application is complete or all requested information is
15
received.
16

(h) An electric utility shall recover from its retail
17
customers all of the costs of the rebates made under a tariff
18
or tariffs approved under this Section, including, but not
19
limited to, the value of the rebates and all costs incurred by
20
the utility to comply with and implement subsections (b),
21
(b-5), (c), and (e) of this Section, consistent with the
22
following provisions:
23

(1) The utility shall defer the full amount of its
24

costs as a regulatory asset. The total costs deferred as a
25

regulatory asset shall be amortized over a 15-year period.
26

The unamortized balance shall be recognized as of December

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31 for a given year. The utility shall also earn a return
2

on the total of the unamortized balance of the regulatory
3

assets, less any deferred taxes related to the unamortized
4

balance, at an annual rate equal to the utility's weighted
5

average cost of capital that includes, based on a year-end
6

capital structure, the utility's actual cost of debt for
7

the applicable calendar year and a cost of equity, which
8

shall be equal to the baseline cost of equity approved by
9

the Commission for the utility's electric distribution
10

rates case effective during the applicable year, whether
11

those rates are set pursuant to Section 9-201,
12

subparagraph (B) of paragraph (3) of subsection (d) of
13

Section 16-108.18, or any successor electric distribution
14

ratemaking paradigm.
15

When an electric utility creates a regulatory asset
16

under the provisions of this paragraph (1) of subsection
17

(h), the costs are recovered over a period during which
18

customers also receive a benefit, which is in the public
19

interest. Accordingly, it is the intent of the General
20

Assembly that an electric utility that elects to create a
21

regulatory asset under the provisions of this paragraph
22

(1) shall recover all of the associated costs, including,
23

but not limited to, its cost of capital as set forth in
24

this paragraph (1). After the Commission has approved the
25

prudence and reasonableness of the costs that comprise the
26

regulatory asset, the electric utility shall be permitted

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to recover all such costs, and the value and
2

recoverability through rates of the associated regulatory
3

asset shall not be limited, altered, impaired, or reduced.
4

To enable the financing of the incremental capital
5

expenditures, including regulatory assets, for electric
6

utilities that serve less than 3,000,000 retail customers
7

but more than 500,000 retail customers in the State, the
8

utility's actual year-end capital structure that includes
9

a common equity ratio, excluding goodwill, of up to and
10

including 50% of the total capital structure shall be
11

deemed reasonable and used to set rates.
12

(2) The utility, at its election, may recover all of
13

the costs as part of a filing for a general increase in
14

rates under Article IX of this Act, as part of an annual
15

filing to update a performance-based rate under Section
16

16-108.18, or through an automatic adjustment clause
17

tariff, provided that nothing in this paragraph (2)
18

permits the double recovery of such costs from customers.
19

If the utility elects to recover the costs it incurs under
20

subsections (b), (b-5), (c), and (e) through an automatic
21

adjustment clause tariff, the utility may file its
22

proposed tariff together with the tariff it files under
23

subsection (b) of this Section or at a later time. The
24

proposed tariff shall provide for an annual
25

reconciliation, less any deferred taxes related to the
26

reconciliation, with interest at an annual rate of return

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equal to the utility's weighted average cost of capital as
2

calculated under paragraph (1) of this subsection (h),
3

including a revenue conversion factor calculated to
4

recover or refund all additional income taxes that may be
5

payable or receivable as a result of that return, of the
6

revenue requirement reflected in rates for each calendar
7

year, beginning with the calendar year in which the
8

utility files its automatic adjustment clause tariff under
9

this subsection (h), with what the revenue requirement
10

would have been had the actual cost information for the
11

applicable calendar year been available at the filing
12

date. The Commission shall review the proposed tariff and
13

may make changes to the tariff that are consistent with
14

this Section and with the Commission's authority under
15

Article IX of this Act, subject to notice and hearing.
16

Following notice and hearing, the Commission shall issue
17

an order approving, or approving with modification, such
18

tariff no later than 240 days after the utility files its
19

tariff.
20

(i) (Blank).
21

(j) No later than 90 days after the Commission enters an
22
order, or order on rehearing, whichever is later, approving an
23
electric utility's proposed tariff under this Section, the
24
electric utility shall provide notice of the availability of
25
rebates under this Section.
26

(k) No later than January 1, 2030, the utilities shall

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1
file with the Commission a report that includes:
2

(1) the number and geographic distribution of
3

participants receiving rebates pursuant to this Section;
4

(2) impacts to energy supply prices and wholesale
5

market activities;
6

(3) impacts on distribution system investments and
7

planning; and
8

(4) any other values deemed relevant by the
9

Commission.
10

(l) Upon petition by the applicable electric utility or on
11
its own motion, the Commission may adjust rebate levels for
12
new customers and make other appropriate changes to the rebate
13
program in a manner that is consistent with the State's clean
14
energy goals and the public interest.
15
(Source: P.A. 103-1066, eff. 2-20-25; 104-458, eff. 6-1-26.)

16

(220 ILCS 5/16-107.9)
17

(This Section may contain text from a Public Act with a
18
delayed effective date
)
19

Sec. 16-107.9.
Virtual power plant program.
20

(a) As used in this Section:
21

"Aggregator" means a third-party entity that participates
22
in the program, other than the electric utility or its
23
affiliate, that (i) represents and aggregates the load of
24
participating customers who collectively have the ability to
25
deploy 100 kilowatts or more of deployment of eligible devices

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and (ii) is responsible for performance of the aggregation in
2
the program.
3

"Battery" means a behind-the-meter energy storage device
4
and associated equipment that operate together to fulfill
5
program requirements.
6

"Commission" means the Illinois Commerce Commission.
7

"Customer" means an active electric service account holder
8
of a utility.
9

"Direct participant" means a customer that enrolls in the
10
program directly with the utility, rather than participating
11
in the program through an aggregator.
12

"Distributed energy resource" has the meaning set forth in
13
Section 16-107.6.
14

"Distributed energy resources management system" means a
15
platform that may be used by distribution system operators or
16
utilities to integrate grid resources, such as distributed
17
energy resources, into system operations.
18

"Eligible device" means a customer or third party-owned
19
distributed energy resource that satisfies the requirements
20
for participation in the program as specified in the relevant
21
program rider. "Eligible device" also means any device that
22
can be controlled to respond to pricing, provide services,
23
including decrease peak electricity demand or shift demand
24
from peak to off-peak periods, or inject power to the grid.
25
"Eligible device" includes, but is not limited to,
26
behind-the-meter energy storage systems, smart thermostats,

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electric vehicle batteries, including fleets, and distributed
2
renewable energy devices paired with one or more energy
3
storage systems.
4

"Emergency event" means an event called by the utility
5
with fewer than 24 hours notice.
6

"Energy storage system" has the meaning set forth in
7
subsection (a) of Section 16-107.6.
8

"Enrolled customer" means a customer that participates in
9
the program through either an aggregator or as a direct
10
participant.
11

"Enrolled device" means an enrolled customer's eligible
12
device, as specified in the relevant tariff.
13

"Enterprise distributed energy resources management
14
system" means a platform operated by the electric utility that
15
interfaces with a grid-edge distributed energy resources
16
management system to integrate distributed energy resources
17
into utility electric system operations.
18

"Grid-edge distributed energy resources management system"
19
means a platform owned by a party other than the electric
20
utility that may be used to integrate distributed energy
21
resources.
22

"Grid event" means a grid condition for which the utility
23
schedules or remotely dispatches enrolled devices to respond
24
to, as specified in the grid service opportunities for each
25
tariff.
26

"Grid service" means a capacity, energy, or ancillary

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1
service that supports grid operations.
2

"Participating customer" means an aggregator or a direct
3
retail customer, as defined in Section 16-102, with one or
4
more eligible devices.
5

"Performance payment" means a payment made to the
6
participant based on the performance of an enrolled device
7
providing a grid service during a grid event.
8

"Performance payment rate" means the compensation rate
9
paid to participants for providing a particular grid service
10
during a grid event.
11

"Smart inverter" has the meaning set forth in subsection
12
(a) of Section 16-107.6.
13

"Upfront payment" means a one-time payment made at the
14
time of enrollment.
15

"Virtual power plant" means an aggregation of
16
behind-the-meter distributed energy resources operated in
17
coordination to provide one or more grid services.
18

(b) The General Assembly finds that:
19

(1) virtual power plants are dynamic load management
20

and energy supply resources that can support grid
21

operations, reduce ratepayer costs, and achieve other
22

important public policy goals;
23

(2) virtual power plants can reduce demand for grid
24

supplied electricity during peak periods, shift
25

electricity consumption out of peak periods, make
26

renewable energy generated during off-peak periods

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available for use during peak periods, supply energy to
2

the grid at desired times, provide frequency regulation,
3

voltage support, and other ancillary services, reduce
4

strain on the distribution system, manage localized peaks,
5

improve system resiliency and reliability, and provide
6

other grid services;
7

(3) virtual power plants can facilitate and optimize
8

the utilization of electrical generation from wind and
9

solar energy to help utilities increase hosting capacity
10

and integrate more renewable energy resources;
11

(4) virtual power plants can reduce costs to
12

ratepayers by utilizing customer-sited resources to
13

provide grid services, avoiding or reducing reliance on
14

fossil-fuel fired peaker plants, avoiding or deferring the
15

need to construct new and more costly grid scale
16

resources, optimizing the use of existing assets, and
17

avoiding or deferring distribution and transmission system
18

upgrades and other grid investments;
19

(5) virtual power plants can promote equity by
20

reducing costs for all ratepayers, expanding access to
21

distributed energy resources among low-income and
22

moderate-income customers through improved distributed
23

energy resource finance ability, and providing other
24

important co-benefits, including reduction in emissions of
25

greenhouse gases and other pollutants, especially in
26

environmental justice and other disadvantaged communities

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1

that host fossil fuel generation plants;
2

(6) the United States Department of Energy estimates
3

that the United States could deploy 80 to 160 gigawatts of
4

virtual power plants by 2030, a tripling of current
5

levels, to support the rapid electrification of vehicles
6

and homes and provide on the order of $10,000,000,000 in
7

ratepayer savings annually. The deployment of virtual
8

power plants can provide energy cost savings and other
9

benefits to the people of Illinois;
10

(7) there are significant barriers to deployment and
11

operation of virtual power plants, including the need for
12

statutory and regulatory guidance and support, greater
13

consistency in virtual power plant programs across
14

regulatory jurisdictions, and for utility commitments to
15

incorporate the use of virtual power plants into system
16

operations and long-term resource planning;
17

(8) it is in the public interest to advance customer
18

choice and leverage the expertise of private, non-utility
19

entities to advance innovation and implement
20

cost-effective clean energy solutions; and
21

(9) the policy of Illinois shall be to maximize the
22

use of virtual power plants comprised of customer-owned
23

and third party-owned distributed energy resources to
24

deliver system services and other benefits through utility
25

administered virtual power plant programs in accordance
26

with the provisions of this amendatory Act of the 104th

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1

General Assembly.
2

(c) No later than December 31, 2028, the Commission shall
3
approve at least one virtual power plant tariff for each
4
electric utility serving more than 300,000 customers in the
5
State as of January 1, 2023. Each utility shall file a tariff
6
or tariffs for approval no later than December 31, 2027 to
7
allow retail customers in the electric utility's service areas
8
to participate in a virtual power plant program proposal
9
consistent with the provisions of this Section. The Commission
10
shall provide opportunities for stakeholders to provide input
11
on the virtual power plant programs proposed for
12
implementation by each utility, which the Commission shall
13
take into consideration in its review of each utility's
14
filing. No later than one year after the utility's filing, the
15
Commission shall approve or modify and approve each utility's
16
virtual power plant program proposal for immediate
17
implementation by the utility.
18

(d) The virtual power plant program filed under subsection
19
(c) shall be developed for implementation through a tariff
20
offering with standard terms and conditions for participation.
21
The virtual power plant program tariff shall allow for
22
customers with battery storage, non-battery storage and
23
electric vehicle technologies to enroll the devices in the
24
program through aggregators or directly with the utility. The
25
virtual power plant program tariff shall:
26

(1) provide a mechanism to incorporate existing

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1

programs, such as smart thermostat demand-response or
2

electric vehicle charging programs
or behavioral
3

demand-response programs
currently offered by the utility,
4

under the virtual power plant program framework;
5

(2) provide grid services opportunities for each
6

eligible technology that customers and aggregators may
7

provide, which shall include, at minimum, reducing the
8

utility's applicable capacity and transmission obligations
9

and capturing daily wholesale energy arbitrage
10

opportunities through provision of grid services;
11

(3) provide additional functions and grid service
12

opportunities that the Commission determines are
13

supportive of efficient planning and operation of the
14

electrical grid, including:
15

(A) minimizing the use of fossil fuels at peak
16

times;
17

(B) local peak demand reductions;
18

(C) locational value;
19

(D) the avoidance or deferral of local
20

transmission or distribution upgrades or capacity
21

expansion;
22

(E) voltage support and other ancillary services;
23

and
24

(F) emergency grid services;
25

(4) provide operational parameters, which shall
26

include, at a minimum:

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1

(A) minimum and maximum numbers of grid events for
2

which the utility may require dispatch from the
3

enrolled distributed energy resources;
4

(B) months of the year that grid events may occur;
5

(C) days of the week that grid events may occur;
6

(D) times of day that grid events may occur;
7

(E) maximum duration of grid events; and
8

(F) minimum day-ahead advance notification
9

requirement of grid events, except for emergency
10

events, as applicable;
11

(5) include provisions for aggregators to participate
12

in the virtual power plant program, participate in the
13

utility's distributed energy resource management system as
14

available, automatically enroll and manage their
15

customers' participation, receive dispatch signals and
16

other communications from the utility, deliver performance
17

measurement and verification data to the utility, and
18

receive virtual power plant program payments directly from
19

the utility;
20

(6) include provisions that provide a standardized
21

process for any eligible aggregator to enroll in the
22

program and authorize the eligible aggregators to manage
23

individual customer device participation without
24

additional authorizations from the utility;
25

(7) include provisions that allow a participating
26

customer with multiple eligible devices to enroll the

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1

technologies either directly without an aggregator or
2

through one or more aggregators in applicable programs
3

under the tariff approved under this Section, provided
4

that no particular device is accounted for more than once;
5

(8) include provisions for direct participant
6

customers to participate with the utility's distributed
7

energy resource management system as available, receive
8

dispatch signals and other communications from the
9

utility, deliver performance measurement and verification
10

data to the utility, and receive virtual power plant
11

program payments directly from the utility. Any provisions
12

implementing this subpart that necessitate the
13

installation of equipment to enable direct participation
14

via the utility shall apply to customers who elect to
15

participate as a direct participant and shall not be
16

required of customers who participate via an aggregator or
17

to customers who do not participate in the virtual power
18

plant program;
19

(9) provide for measurement and verification of
20

battery non-battery, and electric vehicle technologies
21

performance directly at the device without the requirement
22

for the installation of an additional meter;
23

(10) include upfront payment or performance payment
24

compensation mechanisms for the peak reduction service, as
25

well as for non-battery and electric vehicle technologies
26

as the Commission deems appropriate. The performance

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1

payment shall be based on the average capacity provided
2

during grid events. The Commission shall approve
3

additional compensation mechanisms as it determines
4

appropriate for other grid services provided under the
5

battery, non-battery and electric vehicle riders. The
6

virtual power plant program shall not assess penalties for
7

non-performance; provided, however, that the Commission
8

may approve reasonable mechanisms to disenroll customers
9

for continued non-performance;
10

(11) enable low-to-moderate income customers,
11

community-driven community solar projects, and customers
12

whose electric service has not been declared competitive
13

pursuant to Section 16-113 as of July 1, 2011 located in
14

equity investment eligible investment communities to
15

receive a higher upfront enrollment payment. The
16

Commission shall coordinate with State energy officials
17

and departments to make funding from federal programs and
18

such other sources as may be available for use in
19

providing higher upfront payments to customers classes as
20

may be approved by the Commission in accordance with this
21

subsection;
22

(12) provide that the performance payment rate
23

applicable at the time of enrollment shall be for 5 years,
24

after which time the participant may reenroll at the then
25

applicable performance payment rate for an additional
26

5-year term;

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(13) provide for a transition of customers from the
2

scheduled dispatch program described in Section 16-107.6
3

to the virtual power plant program; and
4

(14) allow enrolled customers to participate in other
5

applicable interconnection tariffs and grid service
6

programs outside the virtual power plant program, so long
7

as it does not result in double-counting of benefits for
8

the same grid services.
9

(e) The Commission may adopt other reasonable requirements
10
for participation consistent with this subsection, provided
11
that collateral from an aggregator shall not be required for
12
participation.
13

(f) The utility may contract with a third party-owned
14
distributed energy resource management system provider to
15
assist with program implementation; however, implementation
16
shall not be delayed due to the lack of utility-owned
17
distributed energy resource management system capabilities or
18
third party-owned distributed energy resource management
19
system capabilities.
20

(g) The utility shall not send or receive dispatch signals
21
directly to or from any participating customer represented by
22
an aggregator for an event under the virtual power plant
23
program described in this Section.
24

(h) Participating aggregators shall have capabilities to
25
receive event signals from utilities or utility-contracted
26
distributed energy resources management system providers.

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1

(i) Utilities shall recover reasonably and prudently
2
incurred costs to facilitate the virtual power plant program
3
approved under subsection (c), including, but not limited to,
4
distributed energy resource management systems provider and
5
other service contract costs, operations and maintenance
6
expenses, information technology costs, and other costs,
7
expenses, and investments that the Commission finds necessary
8
and prudent for the development and implementation of the
9
program. The utility shall recover the cost of virtual power
10
plant program upfront payments and performance payments and
11
such other payments made to participants through the tariff
12
filed pursuant to subsection (h) of Section 16-107.6.
13

(j) No later than January 31 of each year, each utility
14
shall file an annual report that includes, but is not limited
15
to:
16

(1) the total capacity enrolled in each program rider
17

developed in accordance with the requirements of Section,
18

broken down by technology type, customer class, and
19

aggregator and direct participant status for each grid
20

service opportunity offered in the prior calendar year;
21

(2) recommendations to increase participation in the
22

virtual power plant program; and
23

(3) any other information that the Commission may
24

require.
25

(k) Each utility shall amend existing tariffs and
26
procedures that limit the ability of customers to participate

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1
in providing grid services under the program, such as
2
limitations on charging energy storage devices with grid
3
energy or exporting energy to the grid from battery discharge.
4

(l) The tariffs approved by the Commission shall not
5
reflect any additional charges, fees, or insurance
6
requirements imposed on those owning or operating
7
demand-response technologies beyond those imposed on similarly
8
situated customers that do not own or operate demand-response
9
technologies.
10

(m) As a condition of participating in the programs
11
described in this Section, prior to enrollment of a customer
12
by an aggregator, the aggregator shall disclose the following:
13

(1) the payments, expressed as an amount or a formula,
14

to be provided to the customer;
15

(2) between the aggregator and customer, who is
16

responsible for paying penalties or fees; and
17

(3) between the aggregator and customer, who is
18

responsible for posting collateral, if required.
19

Any tariff authorized by this Section shall incorporate
20
the requirements under this subsection and shall require the
21
electric utility to establish a complaint and Commission
22
notification process and, on order of the Commission, suspend
23
any aggregator repeatedly or egregiously violating such
24
requirements.
25
(Source: P.A. 104-458, eff. 6-1-26.)

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1

Section 30.
The Utility Data Access Act is amended by
2
changing Section 5-10 as follows:

3

(220 ILCS 33/5-10)
4

(This Section may contain text from a Public Act with a
5
delayed effective date
)
6

Sec. 5-10.
Definitions.
As used in this Act:
7

"Account holder" or "customer" means the person or entity
8
authorized to access or modify utility account details.
9

"Aggregated usage data" means an aggregation of covered
10
usage data, where all data associated with a qualified
11
building or qualified property, including, but not limited to,
12
data from tenant meters and from owner meters, are combined
13
into one collective data point per utility data type, per time
14
period, and where any unique identifiers or other personal
15
information are removed or dissociated from individual meter
16
data.
17

"Aggregation threshold" means 3 or more unique
18
nonresidential qualified accounts or any combination of 5 or
19
more residential and nonresidential unique qualified accounts
20
of a property or building during the period for which data is
21
requested.
22

"Benchmarking tool" means the ENERGY STAR Portfolio
23
Manager web-based tool or any prudent and cost-effective
24
alternative system or tool approved by the Commission should
25
ENERGY STAR Portfolio Manager become inoperative or no longer

HB4995
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1
useful to achieving the policy goals of the State of Illinois
2
that (i) enables the periodic entry of a building's energy use
3
data and other descriptive information about a building and
4
(ii) rates a building's energy efficiency against that of
5
comparable buildings nationwide.
6

"Commission" means the Illinois Commerce Commission.
7

"Covered usage data" means electric data collected from
8
one or more utility meters that reflects the quantity and
9
period of utility usage in the building, property, or portion
10
thereof.
11

"Data recipient" means:
12

(1) an owner of the property or building;
13

(2) an owner of a portion of a property with regard to
14

covered usage data only for the utility consumption the
15

owner or the owner's tenants, if any, pay for and consume
16

in the owned portion;
17

(3) a tenant with regard to covered usage data only
18

for the utility consumption the tenant or the tenant's
19

subtenants, if any, pay for and consume in the space
20

leased by the tenant;
21

(4) the board, in the case of a condominium or
22

cooperative ownership of the property or building; or
23

(5) an agent authorized to receive the covered usage
24

data by anyone in paragraphs (1) through (4).
25

"Property" means:
26

(1) a single tax parcel;

HB4995
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1

(2) 2 or more tax parcels held in the cooperative or
2

condominium form of ownership and governed by a single
3

board of managers; or
4

(3) 2 or more colocated tax parcels owned or
5

controlled by the same entity.
6

"Qualified account" means a utility account that serves
7
some or all of a building or property for which covered usage
8
data is requested and that, as affirmed by the data recipient,
9
was not controlled by the data recipient or its subsidiary
10
during the time period for which covered usage data is
11
requested.
12

"Qualified building" means a building that meets the
13
aggregation threshold.
14

"Qualified data recipient" means a data recipient with
15
respect to a qualified property or qualified building.
16

"Qualified property" means a property that meets the
17
aggregation threshold.
18

"Utility" means an entity that is an electric
or gas

19
utility with over 500,000 customers in this State and that is a
20
public utility, as defined in Section 3-105 of the Public
21
Utilities Act.
22

"Utility data type" means electric
or gas
.
23
(Source: P.A. 104-458, eff. 6-1-26.)

24

Section 35.
The Environmental Protection Act is amended by
25
changing Section 9.15 as follows:

HB4995
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LRB104 19660 AAS 33109 b
1

(415 ILCS 5/9.15)
2

(Text of Section before amendment by P.A. 104-458
)
3

Sec. 9.15.
Greenhouse gases.
4

(a) An air pollution construction permit shall not be
5
required due to emissions of greenhouse gases if the
6
equipment, site, or source is not subject to regulation, as
7
defined by 40 CFR 52.21, as now or hereafter amended, for
8
greenhouse gases or is otherwise not addressed in this Section
9
or by the Board in regulations for greenhouse gases. These
10
exemptions do not relieve an owner or operator from the
11
obligation to comply with other applicable rules or
12
regulations.
13

(b) An air pollution operating permit shall not be
14
required due to emissions of greenhouse gases if the
15
equipment, site, or source is not subject to regulation, as
16
defined by Section 39.5 of this Act, for greenhouse gases or is
17
otherwise not addressed in this Section or by the Board in
18
regulations for greenhouse gases. These exemptions do not
19
relieve an owner or operator from the obligation to comply
20
with other applicable rules or regulations.
21

(c) (Blank).
22

(d) (Blank).
23

(e) (Blank).
24

(f) As used in this Section:
25

"Carbon dioxide emission" means the plant annual CO
2
total

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1
output emission as measured by the United States Environmental
2
Protection Agency in its Emissions & Generation Resource
3
Integrated Database (eGrid), or its successor.
4

"Carbon dioxide equivalent emissions" or "CO
2
e" means the
5
sum total of the mass amount of emissions in tons per year,
6
calculated by multiplying the mass amount of each of the 6
7
greenhouse gases specified in Section 3.207, in tons per year,
8
by its associated global warming potential as set forth in 40
9
CFR 98, subpart A, table A-1 or its successor, and then adding
10
them all together.
11

"Cogeneration" or "combined heat and power" refers to any
12
system that, either simultaneously or sequentially, produces
13
electricity and useful thermal energy from a single fuel
14
source.
15

"Copollutants" refers to the 6 criteria pollutants that
16
have been identified by the United States Environmental
17
Protection Agency pursuant to the Clean Air Act.
18

"Electric generating unit" or "EGU" means a fossil
19
fuel-fired stationary boiler, combustion turbine, or combined
20
cycle system that serves a generator that has a nameplate
21
capacity greater than 25 MWe and produces electricity for
22
sale.
23

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

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LRB104 19660 AAS 33109 b
1

"Equity investment eligible community" or "eligible
2
community" means the geographic areas throughout Illinois that
3
would most benefit from equitable investments by the State
4
designed to combat discrimination and foster sustainable
5
economic growth. Specifically, eligible community means the
6
following areas:
7

(1) areas where residents have been historically
8

excluded from economic opportunities, including
9

opportunities in the energy sector, as defined as R3 areas
10

pursuant to Section 10-40 of the Cannabis Regulation and
11

Tax Act; and
12

(2) areas where residents have been historically
13

subject to disproportionate burdens of pollution,
14

including pollution from the energy sector, as established
15

by environmental justice communities as defined by the
16

Illinois Power Agency pursuant to the Illinois Power
17

Agency Act, excluding any racial or ethnic indicators.
18

"Equity investment eligible person" or "eligible person"
19
means the persons who would most benefit from equitable
20
investments by the State designed to combat discrimination and
21
foster sustainable economic growth. Specifically, eligible
22
person means the following people:
23

(1) persons whose primary residence is in an equity
24

investment eligible community;
25

(2) persons whose primary residence is in a
26

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

HB4995
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1

where the closure of an electric generating unit or mine
2

has been publicly announced or the electric generating
3

unit or mine is in the process of closing or closed within
4

the last 5 years;
5

(3) persons who are graduates of or currently enrolled
6

in the foster care system; or
7

(4) persons who were formerly incarcerated.
8

"Existing emissions" means:
9

(1) for CO
2
e, the total average tons-per-year of CO
2
e
10

emitted by the EGU or large GHG-emitting unit either in
11

the years 2018 through 2020 or, if the unit was not yet in
12

operation by January 1, 2018, in the first 3 full years of
13

that unit's operation; and
14

(2) for any copollutant, the total average
15

tons-per-year of that copollutant emitted by the EGU or
16

large GHG-emitting unit either in the years 2018 through
17

2020 or, if the unit was not yet in operation by January 1,
18

2018, in the first 3 full years of that unit's operation.
19

"Green hydrogen" means a power plant technology in which
20
an EGU creates electric power exclusively from electrolytic
21
hydrogen, in a manner that produces zero carbon and
22
copollutant emissions, using hydrogen fuel that is
23
electrolyzed using a 100% renewable zero carbon emission
24
energy source.
25

"Large greenhouse gas-emitting unit" or "large
26
GHG-emitting unit" means a unit that is an electric generating

HB4995
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LRB104 19660 AAS 33109 b
1
unit or other fossil fuel-fired unit that itself has a
2
nameplate capacity or serves a generator that has a nameplate
3
capacity greater than 25 MWe and that produces electricity,
4
including, but not limited to, coal-fired, coal-derived,
5
oil-fired, natural gas-fired, and cogeneration units.
6

"NO
x
emission rate" means the plant annual NO
x
total output
7
emission rate as measured by the United States Environmental
8
Protection Agency in its Emissions & Generation Resource
9
Integrated Database (eGrid), or its successor, in the most
10
recent year for which data is available.
11

"Public greenhouse gas-emitting units" or "public
12
GHG-emitting unit" means large greenhouse gas-emitting units,
13
including EGUs, that are wholly owned, directly or indirectly,
14
by one or more municipalities, municipal corporations, joint
15
municipal electric power agencies, electric cooperatives, or
16
other governmental or nonprofit entities, whether organized
17
and created under the laws of Illinois or another state.
18

"SO
2
emission rate" means the "plant annual SO
2
total
19
output emission rate" as measured by the United States
20
Environmental Protection Agency in its Emissions & Generation
21
Resource Integrated Database (eGrid), or its successor, in the
22
most recent year for which data is available.
23

(g) All EGUs and large greenhouse gas-emitting units that
24
use coal or oil as a fuel and are not public GHG-emitting units
25
shall permanently reduce all CO
2
e and copollutant emissions to
26
zero no later than January 1, 2030.

HB4995
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1

(h) All EGUs and large greenhouse gas-emitting units that
2
use coal as a fuel and are public GHG-emitting units shall
3
permanently reduce CO
2
e emissions to zero no later than
4
December 31, 2045. Any source or plant with such units must
5
also reduce their CO
2
e emissions by 45% from existing
6
emissions by no later than January 1, 2035. If the emissions
7
reduction requirement is not achieved by December 31, 2035,
8
the plant shall retire one or more units or otherwise reduce
9
its CO
2
e emissions by 45% from existing emissions by June 30,
10
2038.
11

(i) All EGUs and large greenhouse gas-emitting units that
12
use gas as a fuel and are not public GHG-emitting units shall
13
permanently reduce all CO
2
e and copollutant emissions to zero,
14
including through unit retirement or the use of 100% green
15
hydrogen or other similar technology that is commercially
16
proven to achieve zero carbon emissions, according to the
17
following:
18

(1) No later than January 1, 2030: all EGUs and large
19

greenhouse gas-emitting units that have a NO
x
emissions
20

rate of greater than 0.12 lbs/MWh or a SO
2
emission rate of
21

greater than 0.006 lb/MWh, and are located in or within 3
22

miles of an environmental justice community designated as
23

of January 1, 2021 or an equity investment eligible
24

community.
25

(2) No later than January 1, 2040: all EGUs and large
26

greenhouse gas-emitting units that have a NO
x
emission

HB4995
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LRB104 19660 AAS 33109 b
1

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

greater than 0.006 lb/MWh, and are not located in or
3

within 3 miles of an environmental justice community
4

designated as of January 1, 2021 or an equity investment
5

eligible community. After January 1, 2035, each such EGU
6

and large greenhouse gas-emitting unit shall reduce its
7

CO
2
e emissions by at least 50% from its existing emissions
8

for CO
2
e, and shall be limited in operation to, on average,
9

6 hours or less per day, measured over a calendar year, and
10

shall not run for more than 24 consecutive hours except in
11

emergency conditions, as designated by a Regional
12

Transmission Organization or Independent System Operator.
13

(3) No later than January 1, 2035: all EGUs and large
14

greenhouse gas-emitting units that began operation prior
15

to the effective date of this amendatory Act of the 102nd
16

General Assembly and have a NO
x
emission rate of less than
17

or equal to 0.12 lb/MWh and a SO
2
emission rate less than
18

or equal to 0.006 lb/MWh, and are located in or within 3
19

miles of an environmental justice community designated as
20

of January 1, 2021 or an equity investment eligible
21

community. Each such EGU and large greenhouse gas-emitting
22

unit shall reduce its CO
2
e emissions by at least 50% from
23

its existing emissions for CO
2
e no later than January 1,
24

2030.
25

(4) No later than January 1, 2040: All remaining EGUs
26

and large greenhouse gas-emitting units that have a heat

HB4995
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LRB104 19660 AAS 33109 b
1

rate greater than or equal to 7000 BTU/kWh. Each such EGU
2

and Large greenhouse gas-emitting unit shall reduce its
3

CO
2
e emissions by at least 50% from its existing emissions
4

for CO
2
e no later than January 1, 2035.
5

(5) No later than January 1, 2045: all remaining EGUs
6

and large greenhouse gas-emitting units.
7

(j) All EGUs and large greenhouse gas-emitting units that
8
use gas as a fuel and are public GHG-emitting units shall
9
permanently reduce all CO
2
e and copollutant emissions to zero,
10
including through unit retirement or the use of 100% green
11
hydrogen or other similar technology that is commercially
12
proven to achieve zero carbon emissions by January 1, 2045.
13

(k) All EGUs and large greenhouse gas-emitting units that
14
utilize combined heat and power or cogeneration technology
15
shall permanently reduce all CO
2
e and copollutant emissions to
16
zero, including through unit retirement or the use of 100%
17
green hydrogen or other similar technology that is
18
commercially proven to achieve zero carbon emissions by
19
January 1, 2045.
20

(k-5) No EGU or large greenhouse gas-emitting unit that
21
uses gas as a fuel and is not a public GHG-emitting unit may
22
emit, in any 12-month period, CO
2
e or copollutants in excess of
23
that unit's existing emissions for those pollutants.
24

(l) Notwithstanding subsections (g) through (k-5), large
25
GHG-emitting units including EGUs may temporarily continue
26
emitting CO
2
e and copollutants after any applicable deadline

HB4995
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LRB104 19660 AAS 33109 b
1
specified in any of subsections (g) through (k-5) if it has
2
been determined, as described in paragraphs (1) and (2) of
3
this subsection, that ongoing operation of the EGU is
4
necessary to maintain power grid supply and reliability or
5
ongoing operation of large GHG-emitting unit that is not an
6
EGU is necessary to serve as an emergency backup to
7
operations. Up to and including the occurrence of an emission
8
reduction deadline under subsection (i), all EGUs and large
9
GHG-emitting units must comply with the following terms:
10

(1) if an EGU or large GHG-emitting unit that is a
11

participant in a regional transmission organization
12

intends to retire, it must submit documentation to the
13

appropriate regional transmission organization by the
14

appropriate deadline that meets all applicable regulatory
15

requirements necessary to obtain approval to permanently
16

cease operating the large GHG-emitting unit;
17

(2) if any EGU or large GHG-emitting unit that is a
18

participant in a regional transmission organization
19

receives notice that the regional transmission
20

organization has determined that continued operation of
21

the unit is required, the unit may continue operating
22

until the issue identified by the regional transmission
23

organization is resolved. The owner or operator of the
24

unit must cooperate with the regional transmission
25

organization in resolving the issue and must reduce its
26

emissions to zero, consistent with the requirements under

HB4995
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LRB104 19660 AAS 33109 b
1

subsection (g), (h), (i), (j), (k), or (k-5), as
2

applicable, as soon as practicable when the issue
3

identified by the regional transmission organization is
4

resolved; and
5

(3) any large GHG-emitting unit that is not a
6

participant in a regional transmission organization shall
7

be allowed to continue emitting CO
2
e and copollutants
8

after the zero-emission date specified in subsection (g),
9

(h), (i), (j), (k), or (k-5), as applicable, in the
10

capacity of an emergency backup unit if approved by the
11

Illinois Commerce Commission.
12

(m) No variance, adjusted standard, or other regulatory
13
relief otherwise available in this Act may be granted to the
14
emissions reduction and elimination obligations in this
15
Section.
16

(n) By June 30 of each year, beginning in 2025, the Agency
17
shall prepare and publish on its website a report setting
18
forth the actual greenhouse gas emissions from individual
19
units and the aggregate statewide emissions from all units for
20
the prior year.
21

(o) Every 5 years beginning in 2025, the Environmental
22
Protection Agency, Illinois Power Agency, and Illinois
23
Commerce Commission shall jointly prepare, and release
24
publicly, a report to the General Assembly that examines the
25
State's current progress toward its renewable energy resource
26
development goals, the status of CO
2
e and copollutant

HB4995
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LRB104 19660 AAS 33109 b
1
emissions reductions, the current status and progress toward
2
developing and implementing green hydrogen technologies, the
3
current and projected status of electric resource adequacy and
4
reliability throughout the State for the period beginning 5
5
years ahead, and proposed solutions for any findings. The
6
Environmental Protection Agency, Illinois Power Agency, and
7
Illinois Commerce Commission shall consult PJM
8
Interconnection, LLC and Midcontinent Independent System
9
Operator, Inc., or their respective successor organizations
10
regarding forecasted resource adequacy and reliability needs,
11
anticipated new generation interconnection, new transmission
12
development or upgrades, and any announced large GHG-emitting
13
unit closure dates and include this information in the report.
14
The report shall be released publicly by no later than
15
December 15 of the year it is prepared. If the Environmental
16
Protection Agency, Illinois Power Agency, and Illinois
17
Commerce Commission jointly conclude in the report that the
18
data from the regional grid operators, the pace of renewable
19
energy development, the pace of development of energy storage
20
and demand response utilization, transmission capacity, and
21
the CO
2
e and copollutant emissions reductions required by
22
subsection (i) or (k-5) reasonably demonstrate that a resource
23
adequacy shortfall will occur, including whether there will be
24
sufficient in-state capacity to meet the zonal requirements of
25
MISO Zone 4 or the PJM ComEd Zone, per the requirements of the
26
regional transmission organizations, or that the regional

HB4995
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LRB104 19660 AAS 33109 b
1
transmission operators determine that a reliability violation
2
will occur during the time frame the study is evaluating, then
3
the Illinois Power Agency, in conjunction with the
4
Environmental Protection Agency shall develop a plan to reduce
5
or delay CO
2
e and copollutant emissions reductions
6
requirements only to the extent and for the duration necessary
7
to meet the resource adequacy and reliability needs of the
8
State, including allowing any plants whose emission reduction
9
deadline has been identified in the plan as creating a
10
reliability concern to continue operating, including operating
11
with reduced emissions or as emergency backup where
12
appropriate. The plan shall also consider the use of renewable
13
energy, energy storage, demand response, transmission
14
development, or other strategies to resolve the identified
15
resource adequacy shortfall or reliability violation.
16

(1) In developing the plan, the Environmental
17

Protection Agency and the Illinois Power Agency shall hold
18

at least one workshop open to, and accessible at a time and
19

place convenient to, the public and shall consider any
20

comments made by stakeholders or the public. Upon
21

development of the plan, copies of the plan shall be
22

posted and made publicly available on the Environmental
23

Protection Agency's, the Illinois Power Agency's, and the
24

Illinois Commerce Commission's websites. All interested
25

parties shall have 60 days following the date of posting
26

to provide comment to the Environmental Protection Agency

HB4995
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LRB104 19660 AAS 33109 b
1

and the Illinois Power Agency on the plan. All comments
2

submitted to the Environmental Protection Agency and the
3

Illinois Power Agency shall be encouraged to be specific,
4

supported by data or other detailed analyses, and, if
5

objecting to all or a portion of the plan, accompanied by
6

specific alternative wording or proposals. All comments
7

shall be posted on the Environmental Protection Agency's,
8

the Illinois Power Agency's, and the Illinois Commerce
9

Commission's websites. Within 30 days following the end of
10

the 60-day review period, the Environmental Protection
11

Agency and the Illinois Power Agency shall revise the plan
12

as necessary based on the comments received and file its
13

revised plan with the Illinois Commerce Commission for
14

approval.
15

(2) Within 60 days after the filing of the revised
16

plan at the Illinois Commerce Commission, any person
17

objecting to the plan shall file an objection with the
18

Illinois Commerce Commission. Within 30 days after the
19

expiration of the comment period, the Illinois Commerce
20

Commission shall determine whether an evidentiary hearing
21

is necessary. The Illinois Commerce Commission shall also
22

host 3 public hearings within 90 days after the plan is
23

filed. Following the evidentiary and public hearings, the
24

Illinois Commerce Commission shall enter its order
25

approving or approving with modifications the reliability
26

mitigation plan within 180 days.

HB4995
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1

(3) The Illinois Commerce Commission shall only
2

approve the plan if the Illinois Commerce Commission
3

determines that it will resolve the resource adequacy or
4

reliability deficiency identified in the reliability
5

mitigation plan at the least amount of CO
2
e and copollutant
6

emissions, taking into consideration the emissions impacts
7

on environmental justice communities, and that it will
8

ensure adequate, reliable, affordable, efficient, and
9

environmentally sustainable electric service at the lowest
10

total cost over time, taking into account the impact of
11

increases in emissions.
12

(4) If the resource adequacy or reliability deficiency
13

identified in the reliability mitigation plan is resolved
14

or reduced, the Environmental Protection Agency and the
15

Illinois Power Agency may file an amended plan adjusting
16

the reduction or delay in CO
2
e and copollutant emission
17

reduction requirements identified in the plan.
18
(Source: P.A. 102-662, eff. 9-15-21; 102-1031, eff. 5-27-22.)

19

(Text of Section after amendment by P.A. 104-458
)
20

Sec. 9.15.
Greenhouse gases.
21

(a) An air pollution construction permit shall not be
22
required due to emissions of greenhouse gases if the
23
equipment, site, or source is not subject to regulation, as
24
defined by 40 CFR 52.21, as now or hereafter amended, for
25
greenhouse gases or is otherwise not addressed in this Section

HB4995
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LRB104 19660 AAS 33109 b
1
or by the Board in regulations for greenhouse gases. These
2
exemptions do not relieve an owner or operator from the
3
obligation to comply with other applicable rules or
4
regulations.
5

(b) An air pollution operating permit shall not be
6
required due to emissions of greenhouse gases if the
7
equipment, site, or source is not subject to regulation, as
8
defined by Section 39.5 of this Act, for greenhouse gases or is
9
otherwise not addressed in this Section or by the Board in
10
regulations for greenhouse gases. These exemptions do not
11
relieve an owner or operator from the obligation to comply
12
with other applicable rules or regulations.
13

(c) (Blank).
14

(d) (Blank).
15

(e) (Blank).
16

(f) As used in this Section:
17

"Carbon dioxide emission" means the plant annual CO
2
total
18
output emission as measured by the United States Environmental
19
Protection Agency in its Emissions & Generation Resource
20
Integrated Database (eGrid), or its successor.
21

"Carbon dioxide equivalent emissions" or "CO
2
e" means the
22
sum total of the mass amount of emissions in tons per year,
23
calculated by multiplying the mass amount of each of the 6
24
greenhouse gases specified in Section 3.207, in tons per year,
25
by its associated global warming potential as set forth in 40
26
CFR 98, subpart A, table A-1 or its successor, and then adding

HB4995
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1
them all together.
2

"Cogeneration" or "combined heat and power" refers to any
3
system that, either simultaneously or sequentially, produces
4
electricity and useful thermal energy from a single fuel
5
source.
6

"Copollutants" refers to the 6 criteria pollutants that
7
have been identified by the United States Environmental
8
Protection Agency pursuant to the Clean Air Act.
9

"Electric generating unit" or "EGU" means a fossil
10
fuel-fired stationary boiler, combustion turbine, or combined
11
cycle system that serves a generator that has a nameplate
12
capacity greater than 25 MWe and produces electricity for
13
sale.
14

"Environmental justice community" means the definition of
15
that term based on existing methodologies and findings, used
16
and as may be updated by the Illinois Power Agency and its
17
program administrator in the Illinois Solar for All Program.
18

"Equity investment eligible community" or "eligible
19
community" means the geographic areas throughout Illinois that
20
would most benefit from equitable investments by the State
21
designed to combat discrimination and foster sustainable
22
economic growth. Specifically, eligible community means the
23
following areas:
24

(1) areas where residents have been historically
25

excluded from economic opportunities, including
26

opportunities in the energy sector, as defined as R3 areas

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pursuant to Section 10-40 of the Cannabis Regulation and
2

Tax Act; and
3

(2) areas where residents have been historically
4

subject to disproportionate burdens of pollution,
5

including pollution from the energy sector, as established
6

by environmental justice communities as defined by the
7

Illinois Power Agency pursuant to the Illinois Power
8

Agency Act, excluding any racial or ethnic indicators.
9

"Equity investment eligible person" or "eligible person"
10
means the persons who would most benefit from equitable
11
investments by the State designed to combat discrimination and
12
foster sustainable economic growth. Specifically, eligible
13
person means the following people:
14

(1) persons whose primary residence is in an equity
15

investment eligible community;
16

(2) persons whose primary residence is in a
17

municipality, or a county with a population under 100,000,
18

where the closure of an electric generating unit or mine
19

has been publicly announced or the electric generating
20

unit or mine is in the process of closing or closed within
21

the last 5 years;
22

(3) persons who are graduates of or currently enrolled
23

in the foster care system; or
24

(4) persons who were formerly incarcerated.
25

"Existing emissions" means:
26

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

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1

emitted by the EGU or large GHG-emitting unit either in
2

the years 2018 through 2020 or, if the unit was not yet in
3

operation by January 1, 2018, in the first 3 full years of
4

that unit's operation; and
5

(2) for any copollutant, the total average
6

tons-per-year of that copollutant emitted by the EGU or
7

large GHG-emitting unit either in the years 2018 through
8

2020 or, if the unit was not yet in operation by January 1,
9

2018, in the first 3 full years of that unit's operation.
10

"Green hydrogen" means a power plant technology in which
11
an EGU creates electric power exclusively from electrolytic
12
hydrogen, in a manner that produces zero carbon and
13
copollutant emissions, using hydrogen fuel that is
14
electrolyzed using a 100% renewable zero carbon emission
15
energy source.
16

"Large greenhouse gas-emitting unit" or "large
17
GHG-emitting unit" means a unit that is an electric generating
18
unit or other fossil fuel-fired unit that itself has a
19
nameplate capacity or serves a generator that has a nameplate
20
capacity greater than 25 MWe and that produces electricity,
21
including, but not limited to, coal-fired, coal-derived,
22
oil-fired, natural gas-fired, and cogeneration units.
23

"NO
x
emission rate" means the plant annual NO
x
total output
24
emission rate as measured by the United States Environmental
25
Protection Agency in its Emissions & Generation Resource
26
Integrated Database (eGrid), or its successor, in the most

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recent year for which data is available.
2

"Public greenhouse gas-emitting units" or "public
3
GHG-emitting unit" means large greenhouse gas-emitting units,
4
including EGUs, that are wholly owned, directly or indirectly,
5
by one or more municipalities, municipal corporations, joint
6
municipal electric power agencies, electric cooperatives, or
7
other governmental or nonprofit entities, whether organized
8
and created under the laws of Illinois or another state.
9

"SO
2
emission rate" means the "plant annual SO
2
total
10
output emission rate" as measured by the United States
11
Environmental Protection Agency in its Emissions & Generation
12
Resource Integrated Database (eGrid), or its successor, in the
13
most recent year for which data is available.
14

(g) All EGUs and large greenhouse gas-emitting units that
15
use coal or oil as a fuel and are not public GHG-emitting units
16
shall permanently reduce all CO
2
e and copollutant emissions to
17
zero no later than January 1, 2030.
18

(h) All EGUs and large greenhouse gas-emitting units that
19
use coal as a fuel and are public GHG-emitting units shall
20
permanently reduce CO
2
e emissions to zero no later than
21
December 31, 2045. Any source or plant with such units must
22
also reduce their CO
2
e emissions by 45% from existing
23
emissions by no later than January 1, 2035. If the emissions
24
reduction requirement is not achieved by December 31, 2035,
25
the plant shall retire one or more units or otherwise reduce
26
its CO
2
e emissions by 45% from existing emissions by June 30,

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2038.
2

(i) All EGUs and large greenhouse gas-emitting units that
3
use gas as a fuel and are not public GHG-emitting units shall
4
permanently reduce all CO
2
e and copollutant emissions to zero,
5
including through unit retirement or the use of 100% green
6
hydrogen or other similar technology that is commercially
7
proven to achieve zero carbon emissions, according to the
8
following:
9

(1) No later than January 1, 2030: all EGUs and large
10

greenhouse gas-emitting units that have a NO
x
emissions
11

rate of greater than 0.12 lbs/MWh or a SO
2
emission rate of
12

greater than 0.006 lb/MWh, and are located in or within 3
13

miles of an environmental justice community designated as
14

of January 1, 2021 or an equity investment eligible
15

community.
16

(2) No later than January 1, 2040: all EGUs and large
17

greenhouse gas-emitting units that have a NO
x
emission
18

rate of greater than 0.12 lbs/MWh or a SO
2
emission rate
19

greater than 0.006 lb/MWh, and are not located in or
20

within 3 miles of an environmental justice community
21

designated as of January 1, 2021 or an equity investment
22

eligible community. After January 1, 2035, each such EGU
23

and large greenhouse gas-emitting unit shall reduce its
24

CO
2
e emissions by at least 50% from its existing emissions
25

for CO
2
e, and shall be limited in operation to, on average,
26

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

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shall not run for more than 24 consecutive hours except in
2

emergency conditions, as designated by a Regional
3

Transmission Organization or Independent System Operator.
4

(3) No later than January 1, 2035: all EGUs and large
5

greenhouse gas-emitting units that began operation prior
6

to the effective date of this amendatory Act of the 102nd
7

General Assembly and have a NO
x
emission rate of less than
8

or equal to 0.12 lb/MWh and a SO
2
emission rate less than
9

or equal to 0.006 lb/MWh, and are located in or within 3
10

miles of an environmental justice community designated as
11

of January 1, 2021 or an equity investment eligible
12

community. Each such EGU and large greenhouse gas-emitting
13

unit shall reduce its CO
2
e emissions by at least 50% from
14

its existing emissions for CO
2
e no later than January 1,
15

2030.
16

(4) No later than January 1, 2040: All remaining EGUs
17

and large greenhouse gas-emitting units that have a heat
18

rate greater than or equal to 7000 BTU/kWh. Each such EGU
19

and Large greenhouse gas-emitting unit shall reduce its
20

CO
2
e emissions by at least 50% from its existing emissions
21

for CO
2
e no later than January 1, 2035.
22

(5) No later than January 1, 2045: all remaining EGUs
23

and large greenhouse gas-emitting units.
24

(j) All EGUs and large greenhouse gas-emitting units that
25
use gas as a fuel and are public GHG-emitting units shall
26
permanently reduce all CO
2
e and copollutant emissions to zero,

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including through unit retirement or the use of 100% green
2
hydrogen or other similar technology that is commercially
3
proven to achieve zero carbon emissions by January 1, 2045.
4

(k) All EGUs and large greenhouse gas-emitting units that
5
utilize combined heat and power or cogeneration technology
6
shall permanently reduce all CO
2
e and copollutant emissions to
7
zero, including through unit retirement or the use of 100%
8
green hydrogen or other similar technology that is
9
commercially proven to achieve zero carbon emissions by
10
January 1, 2045.
11

(k-5) No EGU or large greenhouse gas-emitting unit that
12
uses gas as a fuel and is not a public GHG-emitting unit may
13
emit, in any 12-month period, CO
2
e or copollutants in excess of
14
that unit's existing emissions for those pollutants.
15

(l) Notwithstanding subsections (g) through (k-5), large
16
GHG-emitting units including EGUs may temporarily continue
17
emitting CO
2
e and copollutants after any applicable deadline
18
specified in any of subsections (g) through (k-5) if it has
19
been determined, as described in paragraphs (1) and (2) of
20
this subsection, that ongoing operation of the EGU is
21
necessary to maintain power grid supply and reliability or
22
ongoing operation of large GHG-emitting unit that is not an
23
EGU is necessary to serve as an emergency backup to
24
operations. Up to and including the occurrence of an emission
25
reduction deadline under subsection (i), all EGUs and large
26
GHG-emitting units must comply with the following terms:

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(1) if an EGU or large GHG-emitting unit that is a
2

participant in a regional transmission organization
3

intends to retire, it must submit documentation to the
4

appropriate regional transmission organization by the
5

appropriate deadline that meets all applicable regulatory
6

requirements necessary to obtain approval to permanently
7

cease operating the large GHG-emitting unit;
8

(2) if any EGU or large GHG-emitting unit that is a
9

participant in a regional transmission organization
10

receives notice that the regional transmission
11

organization has determined that continued operation of
12

the unit is required, the unit may continue operating
13

until the issue identified by the regional transmission
14

organization is resolved. The owner or operator of the
15

unit must cooperate with the regional transmission
16

organization in resolving the issue and must reduce its
17

emissions to zero, consistent with the requirements under
18

subsection (g), (h), (i), (j), (k), or (k-5), as
19

applicable, as soon as practicable when the issue
20

identified by the regional transmission organization is
21

resolved; and
22

(3) any large GHG-emitting unit that is not a
23

participant in a regional transmission organization shall
24

be allowed to continue emitting CO
2
e and copollutants
25

after the zero-emission date specified in subsection (g),
26

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

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capacity of an emergency backup unit if approved by the
2

Illinois Commerce Commission.
3

(m) No variance, adjusted standard, or other regulatory
4
relief otherwise available in this Act may be granted to the
5
emissions reduction and elimination obligations in this
6
Section.
7

(n) By June 30 of each year, beginning in 2025, the Agency
8
shall prepare and publish on its website a report setting
9
forth the actual greenhouse gas emissions from individual
10
units and the aggregate statewide emissions from all units for
11
the prior year.
12

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

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anticipated new generation interconnection, new transmission
2
development or upgrades, and any announced large GHG-emitting
3
unit closure dates and include this information in the report.
4
The report shall be released publicly by no later than
5
December 15 of the year it is prepared. If the Environmental
6
Protection Agency, Illinois Power Agency, and Illinois
7
Commerce Commission jointly conclude in the report that the
8
data from the regional grid operators, the pace of renewable
9
energy development, the pace of development of energy storage
10
and demand response utilization, transmission capacity, and
11
the CO
2
e and copollutant emissions reductions required by
12
subsection (i) or (k-5) reasonably demonstrate that a resource
13
adequacy shortfall will occur, including whether there will be
14
sufficient in-state capacity to meet the zonal requirements of
15
MISO Zone 4 or the PJM ComEd Zone, per the requirements of the
16
regional transmission organizations, or that the regional
17
transmission operators determine that a reliability violation
18
will occur during the time frame the study is evaluating, then
19
the Illinois Power Agency, in conjunction with the
20
Environmental Protection Agency
and in conjunction with the
21
integrated resource plan under Sections 16-201 and 16-202 of
22
the Public Utilities Act,
shall develop a plan to reduce or
23
delay CO
2
e and copollutant emissions reductions requirements
24
only to the extent and for the duration necessary to meet the
25
resource adequacy and reliability needs of the State,
26
including allowing any plants whose emission reduction

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1
deadline has been identified in the plan as creating a
2
reliability concern to continue operating, including operating
3
with reduced emissions or as emergency backup where
4
appropriate. The plan shall also consider the use of renewable
5
energy, energy storage, demand response, transmission
6
development, or other strategies to resolve the identified
7
resource adequacy shortfall or reliability violation.
8

(1)
In developing the plan, the Environmental Protection
9
Agency and the Illinois Power Agency shall hold at least one
10
workshop open to, and accessible at a time and place
11
convenient to, the public and shall consider any comments made
12
by stakeholders or the public. Upon development of the plan,
13
copies of the plan shall be posted and made publicly available
14
on the Environmental Protection Agency's, the Illinois Power
15
Agency's, and the Illinois Commerce Commission's websites.
The

16
All interested parties shall have 60 days following the date
17
of posting to provide comment to the Environmental Protection
18
Agency and the Illinois Power Agency on the plan. All comments
19
submitted to the Environmental Protection Agency and the
20
Illinois Power Agency shall be encouraged to be specific,
21
supported by data or other detailed analyses, and, if
22
objecting to all or a portion of the plan, accompanied by
23
specific alternative wording or proposals. All comments shall
24
be posted on the Environmental Protection Agency's, the
25
Illinois Power Agency's, and the Illinois Commerce
26
Commission's websites. Within 30 days following the end of the

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1
60-day review period, the
Environmental Protection Agency and
2
the Illinois Power Agency shall
revise the plan as necessary
3
based on the comments received and
file
the

its revised
plan
4
with the Illinois Commerce Commission for
review in
5
conjunction with the integrated resource plan under Sections
6
16-201 and 16-202 of the Public Utilities Act

approval
.
7

(2) Within 60 days after the filing of the revised
8

plan at the Illinois Commerce Commission, any person
9

objecting to the plan shall file an objection with the
10

Illinois Commerce Commission. Within 30 days after the
11

expiration of the comment period, the Illinois Commerce
12

Commission shall determine whether an evidentiary hearing
13

is necessary. The Illinois Commerce Commission shall also
14

host 3 public hearings within 90 days after the plan is
15

filed. Following the evidentiary and public hearings, the
16

Illinois Commerce Commission shall enter its order
17

approving or approving with modifications the reliability
18

mitigation plan within 180 days.
19

(3) The Illinois Commerce Commission shall only
20

approve the plan if the Illinois Commerce Commission
21

determines that it will resolve the resource adequacy or
22

reliability deficiency identified in the reliability
23

mitigation plan at the least amount of CO
2
e and copollutant
24

emissions, taking into consideration the emissions impacts
25

on environmental justice communities, and that it will
26

ensure adequate, reliable, affordable, efficient, and

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1

environmentally sustainable electric service at the lowest
2

total cost over time, taking into account the impact of
3

increases in emissions.
4

(4) If the resource adequacy or reliability deficiency
5

identified in the reliability mitigation plan is resolved
6

or reduced, the Environmental Protection Agency and the
7

Illinois Power Agency may file an amended plan adjusting
8

the reduction or delay in CO
2
e and copollutant emission
9

reduction requirements identified in the plan.

10
(Source: P.A. 104-458, eff. 6-1-26.)

11

Section 95.
No acceleration or delay.
Where this Act makes
12
changes in a statute that is represented in this Act by text
13
that is not yet or no longer in effect (for example, a Section
14
represented by multiple versions), the use of that text does
15
not accelerate or delay the taking effect of (i) the changes
16
made by this Act or (ii) provisions derived from any other
17
Public Act.

18

Section 99.
Effective date.
This Act takes effect upon
19
becoming law.

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1

INDEX

2

Statutes amended in order of appearance

3

New Act
4

220 ILCS 5/16-107.6
5

220 ILCS 5/16-107.9
6

220 ILCS 33/5-10
7

415 ILCS 5/9.15

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