Bill Amendment: IL HB1700 | 2025-2026 | 104th General Assembly

NOTE: For additional amemendments please see the Bill Drafting List

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Bill Title: FUNDS-COMMUNITY REINVESTMENT

Status: 2026-06-26 - Public Act . . . . . . . . . 104-0477 [HB1700 Detail]

Download: Illinois-2025-HB1700-Senate_Amendment_002.html

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Sen. Steve Stadelman

Filed: 5/28/2026

 

 

 

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AMENDMENT TO HOUSE BILL 1700
AMENDMENT NO. ______. Amend House Bill 1700, AS AMENDED,
by replacing everything after the enacting clause with the
following:
"Section 5. The Illinois Enterprise Zone Act is amended by
changing Section 5.5 as follows:
(20 ILCS 655/5.5) (from Ch. 67 1/2, par. 609.1)
Sec. 5.5. High Impact Business.
(a) In order to respond to unique opportunities to assist
in the encouragement, development, growth, and expansion of
the private sector through large-scale large scale investment
and development projects, the Department is authorized to
receive and approve applications for the designation of "High
Impact Businesses" in Illinois, for an initial term of 20
years with an option for renewal for a term not to exceed 20
years, subject to the following conditions:

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(1) such applications may be submitted at any time
during the year;
(2) such business is not located, at the time of
designation, in an enterprise zone designated pursuant to
this Act, except for grocery stores, as defined in the
Grocery Initiative Act, and a new battery energy storage
solution facility, as defined by subparagraph (I) of
paragraph (3) of this subsection (a);
(3) the business intends to do, commits to do, or is
one or more of the following:
(A) the business intends to make a minimum
investment of $12,000,000 which will be placed in
service in qualified property and intends to create
500 full-time equivalent jobs at a designated location
in Illinois or intends to make a minimum investment of
$30,000,000 which will be placed in service in
qualified property and intends to retain 1,500
full-time retained jobs at a designated location in
Illinois. The terms "placed in service" and "qualified
property" have the same meanings as described in
subsection (h) of Section 201 of the Illinois Income
Tax Act; or
(B) the business intends to establish a new
electric generating facility at a designated location
in Illinois. "New electric generating facility", for
purposes of this Section, means a newly constructed

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electric generation plant or a newly constructed
generation capacity expansion at an existing electric
generation plant, including the transmission lines and
associated equipment that transfers electricity from
points of supply to points of delivery, and for which
such new foundation construction commenced not sooner
than July 1, 2001. Such facility shall be designed to
provide baseload electric generation and shall operate
on a continuous basis throughout the year; and (i)
shall have an aggregate rated generating capacity of
at least 1,000 megawatts for all new units at one site
if it uses natural gas as its primary fuel and
foundation construction of the facility is commenced
on or before December 31, 2004, or shall have an
aggregate rated generating capacity of at least 400
megawatts for all new units at one site if it uses coal
or gases derived from coal as its primary fuel and
shall support the creation of at least 150 new
Illinois coal mining jobs, or (ii) shall be funded
through a federal Department of Energy grant before
December 31, 2010 and shall support the creation of
Illinois coal mining jobs, or (iii) shall use coal
gasification or integrated gasification-combined cycle
units that generate electricity or chemicals, or both,
and shall support the creation of Illinois coal mining
jobs. The term "placed in service" has the same

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meaning as described in subsection (h) of Section 201
of the Illinois Income Tax Act; or
(B-5) the business intends to establish a new
gasification facility at a designated location in
Illinois. As used in this Section, "new gasification
facility" means a newly constructed coal gasification
facility that generates chemical feedstocks or
transportation fuels derived from coal (which may
include, but are not limited to, methane, methanol,
and nitrogen fertilizer), that supports the creation
or retention of Illinois coal mining jobs, and that
qualifies for financial assistance from the Department
before December 31, 2010. A new gasification facility
does not include a pilot project located within
Jefferson County or within a county adjacent to
Jefferson County for synthetic natural gas from coal;
or
(C) the business intends to establish production
operations at a new coal mine, re-establish production
operations at a closed coal mine, or expand production
at an existing coal mine at a designated location in
Illinois not sooner than July 1, 2001; provided that
the production operations result in the creation of
150 new Illinois coal mining jobs as described in
subdivision (a)(3)(B) of this Section, and further
provided that the coal extracted from such mine is

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utilized as the predominant source for a new electric
generating facility. The term "placed in service" has
the same meaning as described in subsection (h) of
Section 201 of the Illinois Income Tax Act; or
(D) the business intends to construct new
transmission facilities or upgrade existing
transmission facilities at designated locations in
Illinois, for which construction commenced not sooner
than July 1, 2001. For the purposes of this Section,
"transmission facilities" means transmission lines
with a voltage rating of 115 kilovolts or above,
including associated equipment, that transfer
electricity from points of supply to points of
delivery and that transmit a majority of the
electricity generated by a new electric generating
facility designated as a High Impact Business in
accordance with this Section. The term "placed in
service" has the same meaning as described in
subsection (h) of Section 201 of the Illinois Income
Tax Act; or
(E) the business intends to establish a new wind
power facility that will be constructed under a
project labor agreement at a designated location in
Illinois. For purposes of this Section, "new wind
power facility" means a newly constructed electric
generation facility, a newly constructed expansion of

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an existing electric generation facility, or the
replacement of an existing electric generation
facility, including the demolition and removal of an
electric generation facility irrespective of whether
it will be replaced, placed in service or replaced on
or after July 1, 2009, that generates electricity
using wind energy devices, and such facility shall be
deemed to include any permanent structures associated
with the electric generation facility and all
associated transmission lines, substations, and other
equipment related to the generation of electricity
from wind energy devices. For purposes of this
Section, "wind energy device" means any device, with a
nameplate capacity of at least 0.5 megawatts, that is
used in the process of converting kinetic energy from
the wind to generate electricity; or
(E-5) the business intends to establish a new
utility-scale solar facility that will be constructed
under a project labor agreement at a designated
location in Illinois. For purposes of this Section,
"new utility-scale solar power facility" means a newly
constructed electric generation facility, or a newly
constructed expansion of an existing electric
generation facility, placed in service on or after
July 1, 2021, that (i) generates electricity using
photovoltaic cells and (ii) has a nameplate capacity

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that is greater than 5,000 kilowatts, and such
facility shall be deemed to include all associated
transmission lines, substations, energy storage
facilities, and other equipment related to the
generation and storage of electricity from
photovoltaic cells; or
(F) the business commits to (i) make a minimum
investment of $500,000,000, which will be placed in
service in a qualified property, (ii) create 125
full-time equivalent jobs at a designated location in
Illinois, (iii) establish a fertilizer plant at a
designated location in Illinois that complies with the
set-back standards as described in Table 1: Initial
Isolation and Protective Action Distances in the 2012
Emergency Response Guidebook published by the United
States Department of Transportation, (iv) pay a
prevailing wage for employees at that location who are
engaged in construction activities, and (v) secure an
appropriate level of general liability insurance to
protect against catastrophic failure of the fertilizer
plant or any of its constituent systems; in addition,
the business must agree to enter into a construction
project labor agreement including provisions
establishing wages, benefits, and other compensation
for employees performing work under the project labor
agreement at that location; for the purposes of this

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Section, "fertilizer plant" means a newly constructed
or upgraded plant utilizing gas used in the production
of anhydrous ammonia and downstream nitrogen
fertilizer products for resale; for the purposes of
this Section, "prevailing wage" means the hourly cash
wages plus fringe benefits for training and
apprenticeship programs approved by the U.S.
Department of Labor, Bureau of Apprenticeship and
Training, health and welfare, insurance, vacations and
pensions paid generally, in the locality in which the
work is being performed, to employees engaged in work
of a similar character on public works; this paragraph
(F) applies only to businesses that submit an
application to the Department within 60 days after
July 25, 2013 (the effective date of Public Act
98-109); or
(G) the business intends to establish a new
cultured cell material food production facility at a
designated location in Illinois. As used in this
paragraph (G):
"Cultured cell material food production facility"
means a facility (i) at which cultured animal cell
food is developed using animal cell culture
technology, (ii) at which production processes occur
that include the establishment of cell lines and cell
banks, manufacturing controls, and all components and

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inputs, and (iii) that complies with all existing
registrations, inspections, licensing, and approvals
from all applicable and participating State and
federal food agencies, including the Department of
Agriculture, the Department of Public Health, and the
United States Food and Drug Administration, to ensure
that all food production is safe and lawful under
provisions of the Federal Food, Drug and Cosmetic Act
related to the development, production, and storage of
cultured animal cell food.
"New cultured cell material food production
facility" means a newly constructed cultured cell
material food production facility that is placed in
service on or after June 7, 2023 (the effective date of
Public Act 103-9) or a newly constructed expansion of
an existing cultured cell material food production
facility, in a controlled environment, when the
improvements are placed in service on or after June 7,
2023 (the effective date of Public Act 103-9); or
(H) the business is an existing or planned grocery
store, as that term is defined in Section 5 of the
Grocery Initiative Act, and receives financial support
under that Act within the 10 years before submitting
its application under this Act; or
(I) the business intends to establish a new
battery energy storage solution facility that will be

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constructed under a project labor agreement at a
designated location in Illinois. As used in this
paragraph (I):
"New battery energy storage solution facility"
means a newly constructed battery energy storage
facility, a newly constructed expansion of an existing
battery energy storage facility, or the replacement of
an existing battery energy storage facility that
stores electricity using battery devices and other
means. "New battery energy storage solution facility"
includes any permanent structures associated with the
new battery energy storage facility and all associated
transmission lines, substations, and other equipment
that is related to the storage and transmission of
electric power and that has a capacity of not less than
20 megawatt and storage capability of not less than 40
megawatt hours of energy; or
(J) the business intends to construct a new high
voltage direct current converter station at a
designated location in Illinois. As used in this
paragraph, "high voltage direct current converter
station" has the same meaning given to that term in
Section 1-10 of the Illinois Power Agency Act; or
(K) the business intends to construct a new high
voltage direct current converter station facility at a
designated location in Illinois. As used in this

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paragraph, "high voltage direct current converter
station" has the same meaning given to that term in
Section 1-10 of the Illinois Power Agency Act; and
(4) no later than 90 days after an application is
submitted, the Department shall notify the applicant of
the Department's determination of the qualification of the
proposed High Impact Business under this Section.
(a-5) For the purposes of businesses designated as High
Impact Businesses pursuant to subparagraph (E), (E-5), or (I)
of paragraph (3) of subsection (a) of this Section, "project
labor agreement" means a pre-hire collective bargaining
agreement that covers all terms and conditions of employment
on a specific construction project. Project labor agreements
required under subparagraph (E), (E-5), or (I) of paragraph
(3) of subsection (a) of this Section must include, at a
minimum, the following:
(1) provisions establishing the minimum hourly wage
for each class of labor organization employee;
(2) provisions establishing the benefits and other
compensation for each class of labor organization
employee;
(3) provisions establishing that no strike or disputes
will be engaged in by the labor organization employees;
(4) provisions establishing that no lockout or
disputes will be engaged in by the general contractor
building the project; and

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(5) provisions for minorities and women, as defined
under the Business Enterprise for Minorities, Women, and
Persons with Disabilities Act, setting forth goals for
apprenticeship hours to be performed by minorities and
women and setting forth goals for total hours to be
performed by underrepresented minorities and women.
A labor organization and the general contractor building
the project may include other terms and conditions in the
project labor agreement as they deem necessary.
(b) Businesses designated as High Impact Businesses
pursuant to subdivision (a)(3)(A) of this Section shall
qualify for the credits and exemptions described in the
following Acts: Section 9-222 and Section 9-222.1A of the
Public Utilities Act, subsection (h) of Section 201 of the
Illinois Income Tax Act, and Section 1d of the Retailers'
Occupation Tax Act; provided that these credits and exemptions
described in these Acts shall not be authorized until the
minimum investments set forth in subdivision (a)(3)(A) of this
Section have been placed in service in qualified properties
and, in the case of the exemptions described in the Public
Utilities Act and Section 1d of the Retailers' Occupation Tax
Act, the minimum full-time equivalent jobs or full-time
retained jobs set forth in subdivision (a)(3)(A) of this
Section have been created or retained. Businesses designated
as High Impact Businesses under this Section shall also
qualify for the exemption described in Section 5l of the

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Retailers' Occupation Tax Act. The credit provided in
subsection (h) of Section 201 of the Illinois Income Tax Act
shall be applicable to investments in qualified property as
set forth in subdivision (a)(3)(A) of this Section.
(b-5) Businesses designated as High Impact Businesses
pursuant to subdivisions (a)(3)(B), (a)(3)(B-5), (a)(3)(C),
(a)(3)(D), (a)(3)(G), (a)(3)(H), and (a)(3)(K) of this Section
shall qualify for the credits and exemptions described in the
following Acts: Section 51 of the Retailers' Occupation Tax
Act, Section 9-222 and Section 9-222.1A of the Public
Utilities Act, and subsection (h) of Section 201 of the
Illinois Income Tax Act; however, the credits and exemptions
authorized under Section 9-222 and Section 9-222.1A of the
Public Utilities Act, and subsection (h) of Section 201 of the
Illinois Income Tax Act shall not be authorized until the new
electric generating facility, the new gasification facility,
the new transmission facility, the new, expanded, or reopened
coal mine, the new cultured cell material food production
facility, or the existing or planned grocery store is
operational, except that a new electric generating facility
whose primary fuel source is natural gas is eligible only for
the exemption under Section 5l of the Retailers' Occupation
Tax Act.
(b-6) Businesses designated as High Impact Businesses
pursuant to subdivision (a)(3)(E), (a)(3)(E-5), (A)(3)(I), or
(a)(3)(J) of this Section shall qualify for the exemptions

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described in Section 5l of the Retailers' Occupation Tax Act;
any business so designated as a High Impact Business being,
for purposes of this Section, a "Wind Energy Business".
(b-7) Beginning on January 1, 2021, businesses designated
as High Impact Businesses by the Department shall qualify for
the High Impact Business construction jobs credit under
subsection (h-5) of Section 201 of the Illinois Income Tax Act
if the business meets the criteria set forth in subsection (i)
of this Section. The total aggregate amount of credits awarded
under the Blue Collar Jobs Act (Article 20 of Public Act 101-9)
shall not exceed $20,000,000 in any State fiscal year.
(c) High Impact Businesses located in federally designated
foreign trade zones or sub-zones are also eligible for
additional credits, exemptions and deductions as described in
the following Acts: Section 9-221 and Section 9-222.1 of the
Public Utilities Act; and subsection (g) of Section 201, and
Section 203 of the Illinois Income Tax Act.
(d) Except for businesses contemplated under subdivision
(a)(3)(E), (a)(3)(E-5), (a)(3)(G), (a)(3)(H), (A)(3)(I),
(a)(3)(J), or (a)(3)(K) of this Section, existing Illinois
businesses which apply for designation as a High Impact
Business must provide the Department with the prospective plan
for which 1,500 full-time retained jobs would be eliminated in
the event that the business is not designated.
(e) Except for new businesses contemplated under
subdivision (a)(3)(E), subdivision (a)(3)(G), subdivision

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(a)(3)(H), or subdivision (a)(3)(J) of this Section, new
proposed facilities which apply for designation as High Impact
Business must provide the Department with proof of alternative
non-Illinois sites which would receive the proposed investment
and job creation in the event that the business is not
designated as a High Impact Business.
(f) Except for businesses contemplated under subdivision
(a)(3)(E), subdivision (a)(3)(G), subdivision (a)(3)(H),
subdivision (a)(3)(J), or (a)(3)(K) of this Section, in the
event that a business is designated a High Impact Business and
it is later determined after reasonable notice and an
opportunity for a hearing as provided under the Illinois
Administrative Procedure Act, that the business would have
placed in service in qualified property the investments and
created or retained the requisite number of jobs without the
benefits of the High Impact Business designation, the
Department shall be required to immediately revoke the
designation and notify the Director of the Department of
Revenue who shall begin proceedings to recover all wrongfully
exempted State taxes with interest.
(g) The Department shall revoke a High Impact Business
designation if the participating business fails to comply with
the terms and conditions of the designation.
(h) Prior to designating a business, the Department shall
provide the members of the General Assembly and Commission on
Government Forecasting and Accountability with a report

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setting forth the terms and conditions of the designation and
guarantees that have been received by the Department in
relation to the proposed business being designated.
(i) High Impact Business construction jobs credit.
Beginning on January 1, 2021, a High Impact Business may
receive a tax credit against the tax imposed under subsections
(a) and (b) of Section 201 of the Illinois Income Tax Act in an
amount equal to 50% of the amount of the incremental income tax
attributable to High Impact Business construction jobs credit
employees employed in the course of completing a High Impact
Business construction jobs project. However, the High Impact
Business construction jobs credit may equal 75% of the amount
of the incremental income tax attributable to High Impact
Business construction jobs credit employees if the High Impact
Business construction jobs credit project is located in an
underserved area.
The Department shall certify to the Department of Revenue:
(1) the identity of taxpayers that are eligible for the High
Impact Business construction jobs credit; and (2) the amount
of High Impact Business construction jobs credits that are
claimed pursuant to subsection (h-5) of Section 201 of the
Illinois Income Tax Act in each taxable year.
As used in this subsection (i):
"High Impact Business construction jobs credit" means an
amount equal to 50% (or 75% if the High Impact Business
construction project is located in an underserved area) of the

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incremental income tax attributable to High Impact Business
construction job employees. The total aggregate amount of
credits awarded under the Blue Collar Jobs Act (Article 20 of
Public Act 101-9) shall not exceed $20,000,000 in any State
fiscal year
"High Impact Business construction job employee" means a
laborer or worker who is employed by a contractor or
subcontractor in the actual construction work on the site of a
High Impact Business construction job project.
"High Impact Business construction jobs project" means
building a structure or building or making improvements of any
kind to real property, undertaken and commissioned by a
business that was designated as a High Impact Business by the
Department. The term "High Impact Business construction jobs
project" does not include the routine operation, routine
repair, or routine maintenance of existing structures,
buildings, or real property.
"Incremental income tax" means the total amount withheld
during the taxable year from the compensation of High Impact
Business construction job employees.
"Underserved area" means a geographic area that meets one
or more of the following conditions:
(1) the area has a poverty rate of at least 20%
according to the latest American Community Survey;
(2) 35% or more of the families with children in the
area are living below 130% of the poverty line, according

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to the latest American Community Survey;
(3) at least 20% of the households in the area receive
assistance under the Supplemental Nutrition Assistance
Program (SNAP); or
(4) the area has an average unemployment rate, as
determined by the Illinois Department of Employment
Security, that is more than 120% of the national
unemployment average, as determined by the U.S. Department
of Labor, for a period of at least 2 consecutive calendar
years preceding the date of the application.
(j) (Blank).
(j-5) Annually, until construction is completed, a company
seeking High Impact Business Construction Job credits shall
submit a report that, at a minimum, describes the projected
project scope, timeline, and anticipated budget. Once the
project has commenced, the annual report shall include actual
data for the prior year as well as projections for each
additional year through completion of the project. The
Department shall issue detailed reporting guidelines
prescribing the requirements of construction-related reports.
In order to receive credit for construction expenses, the
company must provide the Department with evidence that a
certified third-party executed an Agreed-Upon Procedure (AUP)
verifying the construction expenses or accept the standard
construction wage expense estimated by the Department.
Upon review of the final project scope, timeline, budget,

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and AUP, the Department shall issue a tax credit certificate
reflecting a percentage of the total construction job wages
paid throughout the completion of the project.
(k) Upon 7 business days' notice, each taxpayer shall make
available to each State agency and to federal, State, or local
law enforcement agencies and prosecutors for inspection and
copying at a location within this State during reasonable
hours, the report under subsection (j-5).
(l) The changes made to this Section by Public Act
102-1125, other than the changes in subsection (a), apply to
High Impact Businesses that submit applications on or after
February 3, 2023 (the effective date of Public Act 102-1125).
(Source: P.A. 103-9, eff. 6-7-23; 103-561, eff. 1-1-24;
103-595, eff. 6-26-24; 103-605, eff. 7-1-24; 103-1066, eff.
2-20-25; 104-6, eff. 6-16-25; revised 12-12-25.)
Section 10. The Energy Transition Act is amended by
changing Sections 5-20 and 5-40 as follows:
(20 ILCS 730/5-20)
(Section scheduled to be repealed on September 15, 2045)
Sec. 5-20. Clean Jobs Workforce Network Program.
(a) As used in this Section, "Program" means the Clean
Jobs Workforce Network Program.
(b) Subject to appropriation, the Department shall develop
and, through Regional Administrators, administer the Clean

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Jobs Workforce Network Program to create a network of 14
Program delivery Hub Sites with program elements delivered by
community-based organizations and their subcontractors
geographically distributed across the State including at least
one Hub Site located in or near each of the following areas:
Chicago (South Side), Chicago (Southwest and West Sides),
Waukegan, Rockford, Aurora, Joliet, Peoria, Champaign,
Danville, Decatur, Carbondale, East St. Louis, Kankakee, and
Alton.
(c) In admitting program participants, for each workforce
Hub Site, the Regional Administrators shall:
(1) in each Hub Site where the applicant pool allows:
(A) dedicate at least one-third of program
placements to applicants who reside in a geographic
area that is impacted by economic and environmental
challenges, defined as an area that is both (i) an R3
Area, as defined pursuant to Section 10-40 of the
Cannabis Regulation and Tax Act, and (ii) an
environmental justice community, as defined by the
Illinois Power Agency, excluding any racial or ethnic
indicators used by the agency unless and until the
constitutional basis for their inclusion in
determining program admissions is established. Among
applicants that satisfy these criteria, preference
shall be given to applicants who face barriers to
employment, such as low educational attainment, prior

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involvement with the criminal legal system, and
language barriers; and applicants that are graduates
of or currently enrolled in the foster care system;
and
(B) dedicate at least two-thirds of program
placements to applicants that satisfy the criteria in
paragraph (1) or who reside in a geographic area that
is impacted by economic or environmental challenges,
defined as an area that is either (i) an R3 Area, as
defined pursuant to Section 10-40 of the Cannabis
Regulation and Tax Act, or (ii) an environmental
justice community, as defined by the Illinois Power
Agency, excluding any racial or ethnic indicators used
by the agency unless and until the constitutional
basis for their inclusion in determining program
admissions is established. Among applicants that
satisfy these criteria, preference shall be given to
applicants who face barriers to employment, such as
low educational attainment, prior involvement with the
criminal legal system, and language barriers; and
applicants that are graduates of or currently enrolled
in the foster care system; and
(2) prioritize the remaining program placements for:
applicants who are displaced energy workers as defined in
the Energy Community Reinvestment Act; persons who face
barriers to employment, including low educational

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attainment, prior involvement with the criminal legal
system, and language barriers; and applicants who are
graduates of or currently enrolled in the foster care
system, regardless of the applicant's area of residence.
The Department and Regional Administrators shall protect
the confidentiality of any personal information provided by
program applicants regarding the applicant's status as a
formerly incarcerated person or foster care recipient;
however, the Department or Regional Administrators may publish
aggregated data on the number of participants that were
formerly incarcerated or foster care recipients so long as
that publication protects the identities of those persons.
Any person who applies to the program may elect not to
share with the Department or Regional Administrators whether
he or she is a graduate or currently enrolled in the foster
care system or was formerly convicted.
(d) Program elements for each Hub Site shall be provided
by a community-based organization. The Department shall
initially select a community-based organization in each Hub
Site and shall subsequently select a community-based
organization in each Hub Site every 3 years. Community-based
organizations delivering program elements outlined in
subsection (e) may provide all elements required or may
subcontract to other entities for provision of portions of
program elements, including, but not limited to,
administrative soft and hard skills for program participants,

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delivery of specific training in the core curriculum, or
provision of other support functions for program delivery
compliance.
(e) The Clean Jobs Workforce Hubs Network shall:
(1) coordinate with Energy Transition Navigators: (i)
to increase participation in the Clean Jobs Workforce
Network Program and clean energy and related sector
workforce and training opportunities; (ii) coordinate
recruitment, communications, and ongoing engagement with
potential employers, including, but not limited to,
activities such as job matchmaking initiatives, hosting
events such as job fairs, and collaborating with other Hub
Sites to identify and implement best practices for
employer engagement; and (iii) leverage community-based
organizations, educational institutions, and
community-based and labor-based training providers to
ensure program-eligible individuals across the State have
dedicated and sustained support to enter and complete the
career pipeline for clean energy and related sector jobs;
(2) develop formal partnerships, including formal
sector partnerships between community-based organizations
and entities that provide clean energy jobs, including
businesses, nonprofit organizations, and worker-owned
cooperatives, to ensure that Program participants have
priority access to employment training and hiring
opportunities; and

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(3) implement the Clean Jobs Curriculum to provide,
including, but not limited to, training, certification
preparation, job readiness, and skill development,
including soft skills, math skills, technical skills,
certification test preparation, and other development
needed, to Program participants.
(f) Funding for the Program is subject to appropriation
from the Energy Transition Assistance Fund.
(f-5) The Department and the Department of Corrections
shall jointly conduct activities to support the recruitment of
eligible candidates to the Program, consistent with Section
5-8A-4.2 of the Unified Code of Corrections. The activities
shall include providing information on the community-based
program provider serving the area in which the individual
preparing for release is expected to reside and making
available a process through which an individual may choose to
consent to be contacted by that provider.
(g) The Department shall require submission of quarterly
reports, including program performance metrics by each Hub
Site to the Regional Administrator of their Program Delivery
Area. Program performance metrics include, but are not limited
to:
(1) demographic data, including racial, gender,
residency in eligible communities, and geographic
distribution data, on Program trainees entering and
graduating the Program;

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(2) demographic data, including racial, gender,
residency in eligible communities, and geographic
distribution data, on Program trainees who are placed in
employment, including the percentages of trainees by race,
gender, and geographic categories in each individual job
type or category and whether employment is union,
nonunion, or nonunion via temporary agency;
(3) trainee job acquisition and retention statistics,
including the duration of employment (start and end dates
of hires) by race, gender, and geography;
(4) hourly wages, including hourly overtime pay rate,
and benefits of trainees placed into employment by race,
gender, and geography;
(5) percentage of jobs by race, gender, and geography
held by Program trainees or graduates that are full-time
equivalent positions, meaning that the position held is
full-time, direct, and permanent based on 2,080 hours
worked per year (paid directly by the employer, whose
activities, schedule, and manner of work the employer
controls, and receives pay and benefits in the same manner
as permanent employees); and
(6) qualitative data consisting of open-ended
reporting on pertinent issues, including, but not limited
to, qualitative descriptions accompanying metrics or
identifying key successes and challenges.
(h) Within 3 years after the effective date of this Act,

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the Department shall select an independent evaluator to review
and prepare a report on the performance of the Program and
Regional Administrators.
(Source: P.A. 102-662, eff. 9-15-21; 103-595, eff. 7-1-25.)
(20 ILCS 730/5-40)
(Text of Section before amendment by P.A. 104-458)
(Section scheduled to be repealed on September 15, 2045)
Sec. 5-40. Illinois Climate Works Preapprenticeship
Program.
(a) Subject to appropriation, the Department shall
develop, and through Regional Administrators administer, the
Illinois Climate Works Preapprenticeship Program. The goal of
the Illinois Climate Works Preapprenticeship Program is to
create a network of hubs throughout the State that will
recruit, prescreen, and provide preapprenticeship skills
training, for which participants may attend free of charge and
receive a stipend, to create a qualified, diverse pipeline of
workers who are prepared for careers in the construction and
building trades and clean energy jobs opportunities therein.
Upon completion of the Illinois Climate Works
Preapprenticeship Program, the candidates will be connected to
and prepared to successfully complete an apprenticeship
program.
(b) Each Climate Works Hub that receives funding from the
Energy Transition Assistance Fund shall provide an annual

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report to the Illinois Works Review Panel by April 1 of each
calendar year. The annual report shall include the following
information:
(1) a description of the Climate Works Hub's
recruitment, screening, and training efforts, including a
description of training related to construction and
building trades opportunities in clean energy jobs;
(2) the number of individuals who apply to,
participate in, and complete the Climate Works Hub's
program, broken down by race, gender, age, and veteran
status;
(3) the number of the individuals referenced in
paragraph (2) of this subsection who are initially
accepted and placed into apprenticeship programs in the
construction and building trades; and
(4) the number of individuals referenced in paragraph
(2) of this subsection who remain in apprenticeship
programs in the construction and building trades or have
become journeymen one calendar year after their placement,
as referenced in paragraph (3) of this subsection.
(c) Subject to appropriation, the Department shall provide
funding to 3 Climate Works Hubs throughout the State,
including one to the Illinois Department of Transportation
Region 1, one to the Illinois Department of Transportation
Regions 2 and 3, and one to the Illinois Department of
Transportation Regions 4 and 5. An eligible organization may

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serve as the designated Climate Works Hub for all 5 regions.
Climate Works Hubs shall be awarded grants in multi-year
increments not to exceed 36 months. Each grant shall come with
a one year initial term, with the Department renewing each
year for 2 additional years unless the grantee either declines
to continue or fails to meet reasonable performance measures
that consider apprenticeship programs timeframes. The
Department may take into account experience and performance as
a previous grantee of the Climate Works Hub as part of the
selection criteria for subsequent years.
(d) Each Climate Works Hub that receives funding from the
Energy Transition Assistance Fund shall:
(1) recruit, prescreen, and provide preapprenticeship
training to equity investment eligible persons;
(2) provide training information related to
opportunities and certifications relevant to clean energy
jobs in the construction and building trades; and
(3) provide preapprentices with stipends they receive
that may vary depending on the occupation the individual
is training for.
(d-5) Priority shall be given to Climate Works Hubs that
have an agreement with North American Building Trades Unions
(NABTU) to utilize the Multi-Craft Core Curriculum or
successor curriculums.
(e) Funding for the Program is subject to appropriation
from the Energy Transition Assistance Fund.

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(f) The Department shall adopt any rules deemed necessary
to implement this Section.
(Source: P.A. 102-662, eff. 9-15-21; 102-1031, eff. 5-27-22;
102-1123, eff. 1-27-23.)
(Text of Section after amendment by P.A. 104-458)
(Section scheduled to be repealed on September 15, 2045)
Sec. 5-40. Illinois Climate Works Preapprenticeship
Program.
(a) Subject to appropriation, the Department shall
develop, and through Regional Administrators administer, the
Illinois Climate Works Preapprenticeship Program. The goal of
the Illinois Climate Works Preapprenticeship Program is to
create a network of hubs throughout the State that will
recruit, prescreen, and provide preapprenticeship skills
training, for which participants may attend free of charge and
receive a stipend, to create a qualified, diverse pipeline of
workers who are prepared for careers in the construction and
building trades and clean energy jobs opportunities therein.
Upon completion of the Illinois Climate Works
Preapprenticeship Program, the candidates will be connected to
and prepared to successfully complete an apprenticeship
program.
(b) Each Climate Works Hub that receives funding from the
Energy Transition Assistance Fund shall provide an annual
report to the Illinois Works Review Panel by April 1 of each

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calendar year. The annual report shall include the following
information:
(1) a description of the Climate Works Hub's
recruitment, screening, and training efforts, including a
description of training related to construction and
building trades opportunities in clean energy jobs;
(2) the number of individuals who apply to,
participate in, and complete the Climate Works Hub's
program, broken down by race, gender, age, and veteran
status;
(3) the number of the individuals referenced in
paragraph (2) of this subsection who are initially
accepted and placed into apprenticeship programs in the
construction and building trades; and
(4) the number of individuals referenced in paragraph
(2) of this subsection who remain in apprenticeship
programs in the construction and building trades or have
become journeymen one calendar year after their placement,
as referenced in paragraph (3) of this subsection.
(c) Subject to appropriation, the Department shall provide
funding to 3 Climate Works Hubs throughout the State,
including one to the Illinois Department of Transportation
Region 1, one to the Illinois Department of Transportation
Regions 2 and 3, and one to the Illinois Department of
Transportation Regions 4 and 5. An eligible organization may
serve as the designated Climate Works Hub for all 5 regions.

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Climate Works Hubs shall be awarded grants in multi-year
increments not to exceed 36 months. Each grant shall come with
a one year initial term, with the Department renewing each
year for 2 additional years unless the grantee either declines
to continue or fails to meet reasonable performance measures
that consider apprenticeship programs timeframes. The
Department may take into account experience and performance as
a previous grantee of the Climate Works Hub as part of the
selection criteria for subsequent years.
(d) Each Climate Works Hub that receives funding from the
Energy Transition Assistance Fund shall recruit, prescreen,
and provide preapprenticeship training to program
participants. Each Climate Works Hub that receives funding
from the Energy Transition Assistance Fund shall:
(1) in each Hub Site where the applicant pool allows,
comply with the following:
(A) dedicate at least one-third of Program
placements to applicants who reside in a geographic
area that is impacted by economic and environmental
challenges, defined as an area that is both (i) an R3
Area, as defined pursuant to Section 10-40 of the
Cannabis Regulation and Tax Act, and (ii) an
environmental justice community, as defined by the
Illinois Power Agency under the Illinois Power Agency
Act, excluding any racial or ethnic indicators used by
the Agency unless and until the constitutional basis

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for the inclusion of the factors in determining
Program admissions is established; among applicants
that satisfy these criteria, preference shall be given
to applicants who face barriers to employment,
including low educational attainment, prior
involvement with the criminal justice system, and
language barriers, and applicants that are graduates
of or currently enrolled in the foster care system;
and
(B) dedicate at least two-thirds of Program
placements to applicants who reside in a geographic
area that is impacted by economic or environmental
challenges, defined as an area that is either (i) an R3
Area, as defined pursuant to Section 10-40 of the
Cannabis Regulation and Tax Act, or (ii) an
environmental justice community, as defined by the
Illinois Power Agency in the Illinois Power Agency
Act, excluding any racial or ethnic indicators used by
the Agency unless and until the constitutional basis
for the inclusion of the factors in determining
Program admissions is established; among applicants
that satisfy these criteria, preference shall be given
to applicants who face barriers to employment,
including low educational attainment, prior
involvement with the criminal legal system, and
language barriers, and applicants that are graduates

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of or currently enrolled in the foster care system;
and
(C) prioritize the remaining Program placements
for the following:
(i) applicants who are displaced energy
workers, as defined in the Energy Community
Reinvestment Act;
(ii) persons who face barriers to employment,
including low educational attainment, prior
involvement with the criminal justice system, and
language barriers; and
(iii) applicants who are graduates of or
currently enrolled in the foster care system,
regardless of the applicant's area of residence;
(2) provide training information related to
opportunities and certifications relevant to clean energy
jobs in the construction and building trades; and
(3) provide preapprentices with stipends they receive
that may vary depending on the occupation the individual
is training for.
(d-5) Priority shall be given to Climate Works Hubs that
have an agreement with North American Building Trades Unions
(NABTU) to utilize the Multi-Craft Core Curriculum or
successor curriculums.
(e) Funding for the Program is subject to appropriation
from the Energy Transition Assistance Fund.

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(e-5) The Department and the Department of Corrections
shall jointly conduct activities to support the recruitment of
eligible candidates to the Program, consistent with Section
5-8A-4.2 of the Unified Code of Corrections. The activities
shall include providing information on the community-based
program provider serving the area in which the individual
preparing for release is expected to reside and making
available a process through which an individual may choose to
consent to be contacted by that provider.
(f) The Department shall adopt any rules deemed necessary
to implement this Section.
(Source: P.A. 104-458, eff. 6-1-26.)
Section 15. The Energy Efficient Building Act is amended
by changing Sections 20 and 55 as follows:
(20 ILCS 3125/20)
Sec. 20. Applicability.
(a) The Board shall review and adopt the Code within one
year after its publication. The Code shall take effect within
6 months after it is adopted by the Board, except that,
beginning January 1, 2012, the Code adopted in 2012 shall take
effect on January 1, 2013. Except as otherwise provided in
this Act, the Code shall apply to (i) any new building or
structure in this State for which a building permit
application is received by a municipality or county and (ii)

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beginning on the effective date of this amendatory Act of the
100th General Assembly, each State facility specified in
Section 4.01 of the Capital Development Board Act. In the case
of any addition, alteration, renovation, or repair to an
existing residential or commercial structure, the Code adopted
under this Act applies only to the portions of that structure
that are being added, altered, renovated, or repaired. The
changes made to this Section by this amendatory Act of the 97th
General Assembly shall in no way invalidate or otherwise
affect contracts entered into on or before the effective date
of this amendatory Act of the 97th General Assembly.
(b) The following buildings shall be exempt from the Code
and the Illinois Stretch Energy Code:
(1) Buildings otherwise exempt from the provisions of
a locally adopted building code and buildings that do not
contain a conditioned space.
(2) Buildings that do not use either electricity or
fossil fuel for comfort conditioning. For purposes of
determining whether this exemption applies, a building
will be presumed to be heated by electricity, even in the
absence of equipment used for electric comfort heating,
whenever the building is provided with electrical service
in excess of 100 amps, unless the code enforcement
official determines that this electrical service is
necessary for purposes other than providing electric
comfort heating.

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(3) Historic buildings. This exemption shall apply to
those buildings that are listed on the National Register
of Historic Places or the Illinois Register of Historic
Places, and to those buildings that have been designated
as historically significant by a local governing body that
is authorized to make such designations.
(4) (Blank).
(5) Other buildings specified as exempt by the
International Energy Conservation Code.
(c) Additions, alterations, renovations, or repairs to an
existing building, building system, or portion thereof shall
conform to the provisions of the Code as they relate to new
construction without requiring the unaltered portion of the
existing building or building system to comply with the Code.
The following need not comply with the Code, provided that the
energy use of the building is not increased: (i) storm windows
installed over existing fenestration, (ii) glass-only
replacements in an existing sash and frame, (iii) existing
ceiling, wall, or floor cavities exposed during construction,
provided that these cavities are filled with insulation, and
(iv) construction where the existing roof, wall, or floor is
not exposed.
(d) A unit of local government that does not regulate
energy efficient building standards is not required to adopt,
enforce, or administer the Code; however, any energy efficient
building standards adopted by a unit of local government must

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comply with this Act. If a unit of local government does not
regulate energy efficient building standards, any
construction, renovation, or addition to buildings or
structures is subject to the provisions contained in this Act.
(Source: P.A. 102-662, eff. 9-15-21.)
(20 ILCS 3125/55)
Sec. 55. Illinois Stretch Energy Code.
(a) The Board, in consultation with the Agency, shall
create and adopt the Illinois Stretch Energy Code, to allow
municipalities, counties, and projects authorized or funded by
the Board to achieve more energy efficiency in buildings than
the Illinois Energy Conservation Code through a consistent
pathway across the State. The Illinois Stretch Energy Code
shall be available for adoption by any municipality or county
and shall set minimum energy efficiency requirements, taking
the place of the Illinois Energy Conservation Code within any
municipality or county that adopts the Illinois Stretch Energy
Code.
(b) The Illinois Stretch Energy Code shall have separate
components for commercial and residential buildings, which may
be adopted by the municipality or county jointly or
separately.
(c) The Illinois Stretch Energy Code shall apply to all
projects to which an energy conservation code is applicable
that are authorized or funded in any part by the Board after

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July 1, 2024.
(d) Development of the Illinois Stretch Energy Code shall
be completed and available for adoption by municipalities by
June 30, 2024.
(e) Consistent with the requirements under paragraph (2.5)
of subsection (g) of Section 8-103B of the Public Utilities
Act and under paragraph (2) of subsection (j) of Section 8-104
of the Public Utilities Act, municipalities and counties may
adopt the Illinois Stretch Energy Code and may use utility
programs to support compliance with the Illinois Stretch
Energy Code. The amount of savings from such utility efforts
that may be counted toward achievement of their annual savings
goals shall be based on reasonable estimates of the increase
in savings resulting from the utility efforts, relative to
reasonable approximations of what would have occurred absent
the utility involvement.
(f) The Illinois Stretch Energy Code's residential
components shall:
(1) apply to residential buildings as defined under
Section 10;
(2) set performance targets using a site energy index
with reductions relative to the 2006 International Energy
Conservation Code; and
(3) include stretch energy codes with site energy
index standards and adoption dates as follows: by no later
than June 30, 2024, the Board shall create and adopt a

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stretch energy code with a site energy index no greater
than 0.50 of the 2006 International Energy Conservation
Code; by no later than December 31, 2026, the Board shall
create and adopt a stretch energy code with a site energy
index no greater than 0.40 of the 2006 International
Energy Conservation Code, unless the Board identifies
unanticipated burdens associated with the stretch energy
code adopted in 2023 or 2024, in which case the Board may
adopt a stretch energy code with a site energy index no
greater than 0.42 of the 2006 International Energy
Conservation Code, provided that the more relaxed standard
has a site energy index that is at least 0.05 more
restrictive than the 2024 International Energy
Conservation Code; by no later than December 31, 2029, the
Board shall create and adopt a stretch energy code with a
site energy index no greater than 0.33 of the 2006
International Energy Conservation Code, unless the Board
identifies unanticipated burdens associated with the
stretch energy code adopted in 2025, in which case the
Board may adopt a stretch energy code with a site energy
index no greater than 0.35 of the 2006 International
Energy Conservation Code, but only if that more relaxed
standard has a site energy index that is at least 0.05 more
restrictive than the 2027 International Energy
Conservation Code; and by no later than December 31, 2032,
the Board shall create and adopt a stretch energy code

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with a site energy index no greater than 0.25 of the 2006
International Energy Conservation Code.
(g) The Illinois Stretch Energy Code's commercial
components shall:
(1) apply to commercial buildings as defined under
Section 10;
(2) set performance targets using a site energy index
with reductions relative to the 2006 International Energy
Conservation Code; and
(3) include stretch energy codes with site energy
index standards and adoption dates as follows: by no later
than June 30, 2024, the Board shall create and adopt a
stretch energy code with a site energy index no greater
than 0.60 of the 2006 International Energy Conservation
Code; by no later than December 31, 2026, the Board shall
create and adopt a stretch energy code with a site energy
index no greater than 0.50 of the 2006 International
Energy Conservation Code; by no later than December 31,
2029, the Board shall create and adopt a stretch energy
code with a site energy index no greater than 0.44 of the
2006 International Energy Conservation Code; and by no
later than December 31, 2032, the Board shall create and
adopt a stretch energy code with a site energy index no
greater than 0.39 of the 2006 International Energy
Conservation Code.
(h) The process for the creation of the Illinois Stretch

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Energy Code includes:
(1) within 60 days after the effective date of this
amendatory Act of the 102nd General Assembly, the Capital
Development Board shall meet with the Illinois Energy Code
Advisory Council to advise and provide technical
assistance and recommendations to the Capital Development
Board for the Illinois Stretch Energy Code, which shall:
(A) advise the Capital Development Board on
creation of interim performance targets, code
requirements, and an implementation plan for the
Illinois Stretch Energy Code;
(B) recommend amendments to proposed rules issued
by the Capital Development Board;
(C) recommend complementary programs or policies;
(D) complete recommendations and development for
the Illinois Stretch Energy Code elements and
requirements by December 31, 2023;
(2) As part of its deliberations, the Illinois Energy
Code Advisory Council shall actively solicit input from
other energy code stakeholders and interested parties.
(Source: P.A. 103-4, eff. 5-31-23; 104-315, eff. 1-1-26.)
Section 20. The Illinois Power Agency Act is amended by
changing Section 1-75 as follows:
(20 ILCS 3855/1-75)

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(Text of Section before amendment by P.A. 104-458)
Sec. 1-75. Planning and Procurement Bureau. The Planning
and Procurement Bureau has the following duties and
responsibilities:
(a) The Planning and Procurement Bureau shall each year,
beginning in 2008, develop procurement plans and conduct
competitive procurement processes in accordance with the
requirements of Section 16-111.5 of the Public Utilities Act
for the eligible retail customers of electric utilities that
on December 31, 2005 provided electric service to at least
100,000 customers in Illinois. Beginning with the delivery
year commencing on June 1, 2017, the Planning and Procurement
Bureau shall develop plans and processes for the procurement
of zero emission credits from zero emission facilities in
accordance with the requirements of subsection (d-5) of this
Section. Beginning on the effective date of this amendatory
Act of the 102nd General Assembly, the Planning and
Procurement Bureau shall develop plans and processes for the
procurement of carbon mitigation credits from carbon-free
energy resources in accordance with the requirements of
subsection (d-10) of this Section. The Planning and
Procurement Bureau shall also develop procurement plans and
conduct competitive procurement processes in accordance with
the requirements of Section 16-111.5 of the Public Utilities
Act for the eligible retail customers of small
multi-jurisdictional electric utilities that (i) on December

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31, 2005 served less than 100,000 customers in Illinois and
(ii) request a procurement plan for their Illinois
jurisdictional load. This Section shall not apply to a small
multi-jurisdictional utility until such time as a small
multi-jurisdictional utility requests the Agency to prepare a
procurement plan for their Illinois jurisdictional load. For
the purposes of this Section, the term "eligible retail
customers" has the same definition as found in Section
16-111.5(a) of the Public Utilities Act.
Beginning with the plan or plans to be implemented in the
2017 delivery year, the Agency shall no longer include the
procurement of renewable energy resources in the annual
procurement plans required by this subsection (a), except as
provided in subsection (q) of Section 16-111.5 of the Public
Utilities Act, and shall instead develop a long-term renewable
resources procurement plan in accordance with subsection (c)
of this Section and Section 16-111.5 of the Public Utilities
Act.
In accordance with subsection (c-5) of this Section, the
Planning and Procurement Bureau shall oversee the procurement
by electric utilities that served more than 300,000 retail
customers in this State as of January 1, 2019 of renewable
energy credits from new utility-scale solar projects to be
installed, along with energy storage facilities, at or
adjacent to the sites of electric generating facilities that,
as of January 1, 2016, burned coal as their primary fuel

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source.
(1) The Agency shall each year, beginning in 2008, as
needed, issue a request for qualifications for experts or
expert consulting firms to develop the procurement plans
in accordance with Section 16-111.5 of the Public
Utilities Act. In order to qualify an expert or expert
consulting firm must have:
(A) direct previous experience assembling
large-scale power supply plans or portfolios for
end-use customers;
(B) an advanced degree in economics, mathematics,
engineering, risk management, or a related area of
study;
(C) 10 years of experience in the electricity
sector, including managing supply risk;
(D) expertise in wholesale electricity market
rules, including those established by the Federal
Energy Regulatory Commission and regional transmission
organizations;
(E) expertise in credit protocols and familiarity
with contract protocols;
(F) adequate resources to perform and fulfill the
required functions and responsibilities; and
(G) the absence of a conflict of interest and
inappropriate bias for or against potential bidders or
the affected electric utilities.

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

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

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

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Illinois retail customers of small multi-jurisdictional
electric utilities that (i) on December 31, 2005 served less
than 100,000 customers in Illinois and (ii) request a
procurement plan for their Illinois jurisdictional load.
(c) Renewable portfolio standard.
(1)(A) The Agency shall develop a long-term renewable
resources procurement plan that shall include procurement
programs and competitive procurement events necessary to
meet the goals set forth in this subsection (c). The
initial long-term renewable resources procurement plan
shall be released for comment no later than 160 days after
June 1, 2017 (the effective date of Public Act 99-906).
The Agency shall review, and may revise on an expedited
basis, the long-term renewable resources procurement plan
at least every 2 years, which shall be conducted in
conjunction with the procurement plan under Section
16-111.5 of the Public Utilities Act to the extent
practicable to minimize administrative expense. No later
than 120 days after the effective date of this amendatory
Act of the 103rd General Assembly, the Agency shall
release for comment a revision to the long-term renewable
resources procurement plan, updating elements of the most
recently approved plan as needed to comply with this
amendatory Act of the 103rd General Assembly, and any
long-term renewable resources procurement plan update
published by the Agency but not yet approved by the

10400HB1700sam002 - 49 - LRB104 08228 AAS 38463 a
Illinois Commerce Commission shall be withdrawn. The
long-term renewable resources procurement plans shall be
subject to review and approval by the Commission under
Section 16-111.5 of the Public Utilities Act.
(B) Subject to subparagraph (F) of this paragraph (1),
the long-term renewable resources procurement plan shall
attempt to meet the goals for procurement of renewable
energy credits at levels of at least the following overall
percentages: 13% by the 2017 delivery year; increasing by
at least 1.5% each delivery year thereafter to at least
25% by the 2025 delivery year; increasing by at least 3%
each delivery year thereafter to at least 40% by the 2030
delivery year, and continuing at no less than 40% for each
delivery year thereafter. The Agency shall attempt to
procure 50% by delivery year 2040. The Agency shall
determine the annual increase between delivery year 2030
and delivery year 2040, if any, taking into account energy
demand, other energy resources, and other public policy
goals. In the event of a conflict between these goals and
the new wind, new photovoltaic, and hydropower procurement
requirements described in items (i) through (iii) of
subparagraph (C) of this paragraph (1), the long-term plan
shall prioritize compliance with the new wind, new
photovoltaic, and hydropower procurement requirements
described in items (i) through (iii) of subparagraph (C)
of this paragraph (1) over the annual percentage targets

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described in this subparagraph (B). The Agency shall not
comply with the annual percentage targets described in
this subparagraph (B) by procuring renewable energy
credits that are unlikely to lead to the development of
new renewable resources or new, modernized, or retooled
hydropower facilities.
For the delivery year beginning June 1, 2017, the
procurement plan shall attempt to include, subject to the
prioritization outlined in this subparagraph (B),
cost-effective renewable energy resources equal to at
least 13% of each utility's load for eligible retail
customers and 13% of the applicable portion of each
utility's load for retail customers who are not eligible
retail customers, which applicable portion shall equal 50%
of the utility's load for retail customers who are not
eligible retail customers on February 28, 2017.
For the delivery year beginning June 1, 2018, the
procurement plan shall attempt to include, subject to the
prioritization outlined in this subparagraph (B),
cost-effective renewable energy resources equal to at
least 14.5% of each utility's load for eligible retail
customers and 14.5% of the applicable portion of each
utility's load for retail customers who are not eligible
retail customers, which applicable portion shall equal 75%
of the utility's load for retail customers who are not
eligible retail customers on February 28, 2017.

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For the delivery year beginning June 1, 2019, and for
each year thereafter, the procurement plans shall attempt
to include, subject to the prioritization outlined in this
subparagraph (B), cost-effective renewable energy
resources equal to a minimum percentage of each utility's
load for all retail customers as follows: 16% by June 1,
2019; increasing by 1.5% each year thereafter to 25% by
June 1, 2025; and 25% by June 1, 2026; increasing by at
least 3% each delivery year thereafter to at least 40% by
the 2030 delivery year, and continuing at no less than 40%
for each delivery year thereafter. The Agency shall
attempt to procure 50% by delivery year 2040. The Agency
shall determine the annual increase between delivery year
2030 and delivery year 2040, if any, taking into account
energy demand, other energy resources, and other public
policy goals.
For each delivery year, the Agency shall first
recognize each utility's obligations for that delivery
year under existing contracts. Any renewable energy
credits under existing contracts, including renewable
energy credits as part of renewable energy resources,
shall be used to meet the goals set forth in this
subsection (c) for the delivery year.
(C) The long-term renewable resources procurement plan
described in subparagraph (A) of this paragraph (1) shall
include the procurement of renewable energy credits from

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new projects pursuant to the following terms:
(i) At least 10,000,000 renewable energy credits
delivered annually by the end of the 2021 delivery
year, and increasing ratably to reach 45,000,000
renewable energy credits delivered annually from new
wind and solar projects, from repowered wind projects,
or from retooled hydropower facilities by the end of
delivery year 2030 such that the goals in subparagraph
(B) of this paragraph (1) are met entirely by
procurements of renewable energy credits from new wind
and photovoltaic projects. Of that amount, to the
extent possible, the Agency shall endeavor to procure
45% from new and repowered wind and hydropower
projects and shall procure at least 55% from
photovoltaic projects. Of the amount to be procured
from photovoltaic projects, the Agency shall procure:
at least 50% from solar photovoltaic projects using
the program outlined in subparagraph (K) of this
paragraph (1) from distributed renewable energy
generation devices or community renewable generation
projects; at least 47% from utility-scale solar
projects; at least 3% from brownfield site
photovoltaic projects that are not community renewable
generation projects. The Agency may propose
adjustments to these percentages, including
establishing percentage-based goals for the

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procurement of renewable energy credits from
modernized or retooled hydropower facilities and
repowered wind projects, through its long-term
renewable resources plan described in subparagraph (A)
of this paragraph (1) as necessary based on developer
interest, market conditions, budget considerations,
resource adequacy needs, or other factors.
In developing the long-term renewable resources
procurement plan, the Agency shall consider other
approaches, in addition to competitive procurements,
that can be used to procure renewable energy credits
from brownfield site photovoltaic projects and thereby
help return blighted or contaminated land to
productive use while enhancing public health and the
well-being of Illinois residents, including those in
environmental justice communities, as defined using
existing methodologies and findings used by the Agency
and its Administrator in its Illinois Solar for All
Program. The Agency shall also consider other
approaches, in addition to competitive procurements,
to procure renewable energy credits from new and
existing hydropower facilities to support the
development and maintenance of these facilities. The
Agency shall explore options to convert existing dams
but shall not consider approaches to develop new dams
where they do not already exist. To encourage the

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continued operation of utility-scale wind projects,
the Agency shall consider and may propose other
approaches in addition to competitive procurements to
procure renewable energy credits from repowered wind
projects.
(ii) In any given delivery year, if forecasted
expenses are less than the maximum budget available
under subparagraph (E) of this paragraph (1), the
Agency shall continue to procure new renewable energy
credits until that budget is exhausted in the manner
outlined in item (i) of this subparagraph (C).
(iii) For purposes of this Section:
"New wind projects" means wind renewable energy
facilities that are energized after June 1, 2017 for
the delivery year commencing June 1, 2017.
"New photovoltaic projects" means photovoltaic
renewable energy facilities that are energized after
June 1, 2017. Photovoltaic projects developed under
Section 1-56 of this Act shall not apply towards the
new photovoltaic project requirements in this
subparagraph (C).
"Repowered wind projects" means utility-scale wind
projects featuring the removal, replacement, or
expansion of turbines at an existing project site, as
defined in the long-term renewable resources
procurement plan, after the effective date of this

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amendatory Act of the 103rd General Assembly.
Renewable energy credit contract awards used to
support repowered wind projects shall only cover the
incremental increase in facility electricity
production resultant from repowering.
For purposes of calculating whether the Agency has
procured enough new wind and solar renewable energy
credits required by this subparagraph (C), renewable
energy facilities that have a multi-year renewable
energy credit delivery contract with the utility
through at least delivery year 2030 shall be
considered new, however no renewable energy credits
from contracts entered into before June 1, 2021 shall
be used to calculate whether the Agency has procured
the correct proportion of new wind and new solar
contracts described in this subparagraph (C) for
delivery year 2021 and thereafter.
(D) Renewable energy credits shall be cost effective.
For purposes of this subsection (c), "cost effective"
means that the costs of procuring renewable energy
resources do not cause the limit stated in subparagraph
(E) of this paragraph (1) to be exceeded and, for
renewable energy credits procured through a competitive
procurement event, do not exceed benchmarks based on
market prices for like products in the region. For
purposes of this subsection (c), "like products" means

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contracts for renewable energy credits from the same or
substantially similar technology, same or substantially
similar vintage (new or existing), the same or
substantially similar quantity, and the same or
substantially similar contract length and structure.
Benchmarks shall reflect development, financing, or
related costs resulting from requirements imposed through
other provisions of State law, including, but not limited
to, requirements in subparagraphs (P) and (Q) of this
paragraph (1) and the Renewable Energy Facilities
Agricultural Impact Mitigation Act. Confidential
benchmarks shall be developed by the procurement
administrator, in consultation with the Commission staff,
Agency staff, and the procurement monitor and shall be
subject to Commission review and approval. If price
benchmarks for like products in the region are not
available, the procurement administrator shall establish
price benchmarks based on publicly available data on
regional technology costs and expected current and future
regional energy prices. The benchmarks in this Section
shall not be used to curtail or otherwise reduce
contractual obligations entered into by or through the
Agency prior to June 1, 2017 (the effective date of Public
Act 99-906).
(E) For purposes of this subsection (c), the required
procurement of cost-effective renewable energy resources

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for a particular year commencing prior to June 1, 2017
shall be measured as a percentage of the actual amount of
electricity (megawatt-hours) supplied by the electric
utility to eligible retail customers in the delivery year
ending immediately prior to the procurement, and, for
delivery years commencing on and after June 1, 2017, the
required procurement of cost-effective renewable energy
resources for a particular year shall be measured as a
percentage of the actual amount of electricity
(megawatt-hours) delivered by the electric utility in the
delivery year ending immediately prior to the procurement,
to all retail customers in its service territory. For
purposes of this subsection (c), the amount paid per
kilowatthour means the total amount paid for electric
service expressed on a per kilowatthour basis. For
purposes of this subsection (c), the total amount paid for
electric service includes without limitation amounts paid
for supply, transmission, capacity, distribution,
surcharges, and add-on taxes.
Notwithstanding the requirements of this subsection
(c), and except as provided in subparagraph (E-5) of
paragraph (1) of this subsection (c), the total of
renewable energy resources procured under the procurement
plan for any single year shall be subject to the
limitations of this subparagraph (E). Such procurement
shall be reduced for all retail customers based on the

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amount necessary to limit the annual estimated average net
increase due to the costs of these resources included in
the amounts paid by eligible retail customers in
connection with electric service to no more than 4.25% of
the amount paid per kilowatthour by those customers during
the year ending May 31, 2009. To arrive at a maximum dollar
amount of renewable energy resources to be procured for
the particular delivery year, the resulting per
kilowatthour amount shall be applied to the actual amount
of kilowatthours of electricity delivered, or applicable
portion of such amount as specified in paragraph (1) of
this subsection (c), as applicable, by the electric
utility in the delivery year immediately prior to the
procurement to all retail customers in its service
territory. The calculations required by this subparagraph
(E) shall be made only once for each delivery year at the
time that the renewable energy resources are procured.
Once the determination as to the amount of renewable
energy resources to procure is made based on the
calculations set forth in this subparagraph (E) and the
contracts procuring those amounts are executed between the
seller and applicable electric utility, no subsequent rate
impact determinations shall be made and no adjustments to
those contract amounts shall be allowed. As provided in
subparagraph (E-5) of paragraph (1) of this subsection
(c), the seller shall be entitled to full, prompt, and

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

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

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of this subparagraph (E-5) is made, the Agency shall
analyze existing contract obligations, projected
prices for indexed renewable energy credit contracts
executed under item (v) of subparagraph (G) of
paragraph (1) of subsection (c) of Section 1-75 of
this Act, and expected collections authorized under
subparagraph (E) to determine whether and to what
extent the limitations of subparagraph (E) would be
exceeded by additional renewable energy credit
procurement contract awards.
(aa) If the Agency determines that additional
renewable energy credit procurement contract
awards could be made without exceeding the
limitations of subparagraph (E), then the
procurements shall be authorized at a scale
determined not to exceed the limitations of
subparagraph (E) in a manner consistent with the
priorities of this Section.
(bb) If the Agency determines that additional
renewable energy credit procurement contract
awards cannot be made without exceeding the
limitations of subparagraph (E), then the Agency
shall suspend any new contract awards for the
procurement of renewable energy credits until a
new rate impact determination is made under
subparagraph (E).

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(cc) Agency determinations made under this
item (iv) shall be detailed and comprehensive and,
if not made through the Agency's Long-Term
Renewable Resources Procurement Plan, shall be
filed as a compliance filing in the most recent
docketed proceeding approving the Agency's
Long-Term Renewable Resources Procurement Plan.
(dd) With respect to the procurement of
renewable energy credits authorized through
programs administered under subsection (b) of
Section 1-56 and subparagraphs (K) through (M) of
paragraph (1) of subsection (k) of Section 1-75 of
this Act, the award of contracts for the
procurement of renewable energy credits shall be
suspended or reduced only at the conclusion of the
program year in which the notice provided for
under item (iii) of this subparagraph (E-5) is
made.
(ee) The contract shall provide that, so long
as at least one of: (i) the cost recovery
mechanisms referenced in subsection (k) of Section
16-108 and subsection (l) of Section 16-111.5 of
the Public Utilities Act remains in full force
without limitation or (ii) the utility is
otherwise authorized and or entitled to full,
prompt, and uninterrupted recovery of its costs

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through any other mechanism, then such seller
shall be entitled to full, prompt, and
uninterrupted payment under the applicable
contract notwithstanding the application of this
subparagraph (E).
(F) If the limitation on the amount of renewable
energy resources procured in subparagraph (E) of this
paragraph (1) prevents the Agency from meeting all of the
goals in this subsection (c), the Agency's long-term plan
shall prioritize compliance with the requirements of this
subsection (c) regarding renewable energy credits in the
following order:
(i) renewable energy credits under existing
contractual obligations as of June 1, 2021;
(i-5) funding for the Illinois Solar for All
Program, as described in subparagraph (O) of this
paragraph (1);
(ii) renewable energy credits necessary to comply
with the new wind and new photovoltaic procurement
requirements described in items (i) through (iii) of
subparagraph (C) of this paragraph (1); and
(iii) renewable energy credits necessary to meet
the remaining requirements of this subsection (c).
(G) The following provisions shall apply to the
Agency's procurement of renewable energy credits under
this subsection (c):

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(i) Notwithstanding whether a long-term renewable
resources procurement plan has been approved, the
Agency shall conduct an initial forward procurement
for renewable energy credits from new utility-scale
wind projects within 160 days after June 1, 2017 (the
effective date of Public Act 99-906). For the purposes
of this initial forward procurement, the Agency shall
solicit 15-year contracts for delivery of 1,000,000
renewable energy credits delivered annually from new
utility-scale wind projects to begin delivery on June
1, 2019, if available, but not later than June 1, 2021,
unless the project has delays in the establishment of
an operating interconnection with the applicable
transmission or distribution system as a result of the
actions or inactions of the transmission or
distribution provider, or other causes for force
majeure as outlined in the procurement contract, in
which case, not later than June 1, 2022. Payments to
suppliers of renewable energy credits shall commence
upon delivery. Renewable energy credits procured under
this initial procurement shall be included in the
Agency's long-term plan and shall apply to all
renewable energy goals in this subsection (c).
(ii) Notwithstanding whether a long-term renewable
resources procurement plan has been approved, the
Agency shall conduct an initial forward procurement

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

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procurement plan revision described in Section
16-111.5 of the Public Utilities Act, the Agency shall
conduct at least one subsequent forward procurement
for renewable energy credits from new utility-scale
wind projects, new utility-scale solar projects, and
new brownfield site photovoltaic projects within 240
days after the effective date of this amendatory Act
of the 102nd General Assembly in quantities necessary
to meet the requirements of subparagraph (C) of this
paragraph (1) through the delivery year beginning June
1, 2021.
(iv) Notwithstanding whether the Commission has
approved the periodic long-term renewable resources
procurement plan revision described in Section
16-111.5 of the Public Utilities Act, the Agency shall
open capacity for each category in the Adjustable
Block program within 90 days after the effective date
of this amendatory Act of the 102nd General Assembly
manner:
(1) The Agency shall open the first block of
annual capacity for the category described in item
(i) of subparagraph (K) of this paragraph (1). The
first block of annual capacity for item (i) shall
be for at least 75 megawatts of total nameplate
capacity. The price of the renewable energy credit
for this block of capacity shall be 4% less than

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the price of the last open block in this category.
Projects on a waitlist shall be awarded contracts
first in the order in which they appear on the
waitlist. Notwithstanding anything to the
contrary, for those renewable energy credits that
qualify and are procured under this subitem (1) of
this item (iv), the renewable energy credit
delivery contract value shall be paid in full,
based on the estimated generation during the first
15 years of operation, by the contracting
utilities at the time that the facility producing
the renewable energy credits is interconnected at
the distribution system level of the utility and
verified as energized and in compliance by the
Program Administrator. The electric utility shall
receive and retire all renewable energy credits
generated by the project for the first 15 years of
operation. Renewable energy credits generated by
the project thereafter shall not be transferred
under the renewable energy credit delivery
contract with the counterparty electric utility.
(2) The Agency shall open the first block of
annual capacity for the category described in item
(ii) of subparagraph (K) of this paragraph (1).
The first block of annual capacity for item (ii)
shall be for at least 75 megawatts of total

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nameplate capacity.
(A) The price of the renewable energy
credit for any project on a waitlist for this
category before the opening of this block
shall be 4% less than the price of the last
open block in this category. Projects on the
waitlist shall be awarded contracts first in
the order in which they appear on the
waitlist. Any projects that are less than or
equal to 25 kilowatts in size on the waitlist
for this capacity shall be moved to the
waitlist for paragraph (1) of this item (iv).
Notwithstanding anything to the contrary,
projects that were on the waitlist prior to
opening of this block shall not be required to
be in compliance with the requirements of
subparagraph (Q) of this paragraph (1) of this
subsection (c). Notwithstanding anything to
the contrary, for those renewable energy
credits procured from projects that were on
the waitlist for this category before the
opening of this block 20% of the renewable
energy credit delivery contract value, based
on the estimated generation during the first
15 years of operation, shall be paid by the
contracting utilities at the time that the

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facility producing the renewable energy
credits is interconnected at the distribution
system level of the utility and verified as
energized by the Program Administrator. The
remaining portion shall be paid ratably over
the subsequent 4-year period. The electric
utility shall receive and retire all renewable
energy credits generated by the project during
the first 15 years of operation. Renewable
energy credits generated by the project
thereafter shall not be transferred under the
renewable energy credit delivery contract with
the counterparty electric utility.
(B) The price of renewable energy credits
for any project not on the waitlist for this
category before the opening of the block shall
be determined and published by the Agency.
Projects not on a waitlist as of the opening
of this block shall be subject to the
requirements of subparagraph (Q) of this
paragraph (1), as applicable. Projects not on
a waitlist as of the opening of this block
shall be subject to the contract provisions
outlined in item (iii) of subparagraph (L) of
this paragraph (1). The Agency shall strive to
publish updated prices and an updated

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renewable energy credit delivery contract as
quickly as possible.
(3) For opening the first 2 blocks of annual
capacity for projects participating in item (iii)
of subparagraph (K) of paragraph (1) of subsection
(c), projects shall be selected exclusively from
those projects on the ordinal waitlists of
community renewable generation projects
established by the Agency based on the status of
those ordinal waitlists as of December 31, 2020,
and only those projects previously determined to
be eligible for the Agency's April 2019 community
solar project selection process.
The first 2 blocks of annual capacity for item
(iii) shall be for 250 megawatts of total
nameplate capacity, with both blocks opening
simultaneously under the schedule outlined in the
paragraphs below. Projects shall be selected as
follows:
(A) The geographic balance of selected
projects shall follow the Group classification
found in the Agency's Revised Long-Term
Renewable Resources Procurement Plan, with 70%
of capacity allocated to projects on the Group
B waitlist and 30% of capacity allocated to
projects on the Group A waitlist.

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(B) Contract awards for waitlisted
projects shall be allocated proportionate to
the total nameplate capacity amount across
both ordinal waitlists associated with that
applicant firm or its affiliates, subject to
the following conditions.
(i) Each applicant firm having a
waitlisted project eligible for selection
shall receive no less than 500 kilowatts
in awarded capacity across all groups, and
no approved vendor may receive more than
20% of each Group's waitlist allocation.
(ii) Each applicant firm, upon
receiving an award of program capacity
proportionate to its waitlisted capacity,
may then determine which waitlisted
projects it chooses to be selected for a
contract award up to that capacity amount.
(iii) Assuming all other program
requirements are met, applicant firms may
adjust the nameplate capacity of applicant
projects without losing waitlist
eligibility, so long as no project is
greater than 2,000 kilowatts in size.
(iv) Assuming all other program
requirements are met, applicant firms may

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adjust the expected production associated
with applicant projects, subject to
verification by the Program Administrator.
(C) After a review of affiliate
information and the current ordinal waitlists,
the Agency shall announce the nameplate
capacity award amounts associated with
applicant firms no later than 90 days after
the effective date of this amendatory Act of
the 102nd General Assembly.
(D) Applicant firms shall submit their
portfolio of projects used to satisfy those
contract awards no less than 90 days after the
Agency's announcement. The total nameplate
capacity of all projects used to satisfy that
portfolio shall be no greater than the
Agency's nameplate capacity award amount
associated with that applicant firm. An
applicant firm may decline, in whole or in
part, its nameplate capacity award without
penalty, with such unmet capacity rolled over
to the next block opening for project
selection under item (iii) of subparagraph (K)
of this subsection (c). Any projects not
included in an applicant firm's portfolio may
reapply without prejudice upon the next block

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reopening for project selection under item
(iii) of subparagraph (K) of this subsection
(c).
(E) The renewable energy credit delivery
contract shall be subject to the contract and
payment terms outlined in item (iv) of
subparagraph (L) of this subsection (c).
Contract instruments used for this
subparagraph shall contain the following
terms:
(i) Renewable energy credit prices
shall be fixed, without further adjustment
under any other provision of this Act or
for any other reason, at 10% lower than
prices applicable to the last open block
for this category, inclusive of any adders
available for achieving a minimum of 50%
of subscribers to the project's nameplate
capacity being residential or small
commercial customers with subscriptions of
below 25 kilowatts in size;
(ii) A requirement that a minimum of
50% of subscribers to the project's
nameplate capacity be residential or small
commercial customers with subscriptions of
below 25 kilowatts in size;

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(iii) Permission for the ability of a
contract holder to substitute projects
with other waitlisted projects without
penalty should a project receive a
non-binding estimate of costs to construct
the interconnection facilities and any
required distribution upgrades associated
with that project of greater than 30 cents
per watt AC of that project's nameplate
capacity. In developing the applicable
contract instrument, the Agency may
consider whether other circumstances
outside of the control of the applicant
firm should also warrant project
substitution rights.
The Agency shall publish a finalized
updated renewable energy credit delivery
contract developed consistent with these terms
and conditions no less than 30 days before
applicant firms must submit their portfolio of
projects pursuant to item (D).
(F) To be eligible for an award, the
applicant firm shall certify that not less
than prevailing wage, as determined pursuant
to the Illinois Prevailing Wage Act, was or
will be paid to employees who are engaged in

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construction activities associated with a
selected project.
(4) The Agency shall open the first block of
annual capacity for the category described in item
(iv) of subparagraph (K) of this paragraph (1).
The first block of annual capacity for item (iv)
shall be for at least 50 megawatts of total
nameplate capacity. Renewable energy credit prices
shall be fixed, without further adjustment under
any other provision of this Act or for any other
reason, at the price in the last open block in the
category described in item (ii) of subparagraph
(K) of this paragraph (1). Pricing for future
blocks of annual capacity for this category may be
adjusted in the Agency's second revision to its
Long-Term Renewable Resources Procurement Plan.
Projects in this category shall be subject to the
contract terms outlined in item (iv) of
subparagraph (L) of this paragraph (1).
(5) The Agency shall open the equivalent of 2
years of annual capacity for the category
described in item (v) of subparagraph (K) of this
paragraph (1). The first block of annual capacity
for item (v) shall be for at least 10 megawatts of
total nameplate capacity. Notwithstanding the
provisions of item (v) of subparagraph (K) of this

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paragraph (1), for the purpose of this initial
block, the agency shall accept new project
applications intended to increase the diversity of
areas hosting community solar projects, the
business models of projects, and the size of
projects, as described by the Agency in its
long-term renewable resources procurement plan
that is approved as of the effective date of this
amendatory Act of the 102nd General Assembly.
Projects in this category shall be subject to the
contract terms outlined in item (iii) of
subsection (L) of this paragraph (1).
(6) The Agency shall open the first blocks of
annual capacity for the category described in item
(vi) of subparagraph (K) of this paragraph (1),
with allocations of capacity within the block
generally matching the historical share of block
capacity allocated between the category described
in items (i) and (ii) of subparagraph (K) of this
paragraph (1). The first two blocks of annual
capacity for item (vi) shall be for at least 75
megawatts of total nameplate capacity. The price
of renewable energy credits for the blocks of
capacity shall be 4% less than the price of the
last open blocks in the categories described in
items (i) and (ii) of subparagraph (K) of this

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paragraph (1). Pricing for future blocks of annual
capacity for this category may be adjusted in the
Agency's second revision to its Long-Term
Renewable Resources Procurement Plan. Projects in
this category shall be subject to the applicable
contract terms outlined in items (ii) and (iii) of
subparagraph (L) of this paragraph (1).
(v) Upon the effective date of this amendatory Act
of the 102nd General Assembly, for all competitive
procurements and any procurements of renewable energy
credit from new utility-scale wind and new
utility-scale photovoltaic projects, the Agency shall
procure indexed renewable energy credits and direct
respondents to offer a strike price.
(1) The purchase price of the indexed
renewable energy credit payment shall be
calculated for each settlement period. That
payment, for any settlement period, shall be equal
to the difference resulting from subtracting the
strike price from the index price for that
settlement period. If this difference results in a
negative number, the indexed REC counterparty
shall owe the seller the absolute value multiplied
by the quantity of energy produced in the relevant
settlement period. If this difference results in a
positive number, the seller shall owe the indexed

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REC counterparty this amount multiplied by the
quantity of energy produced in the relevant
settlement period.
(2) Parties shall cash settle every month,
summing up all settlements (both positive and
negative, if applicable) for the prior month.
(3) To ensure funding in the annual budget
established under subparagraph (E) for indexed
renewable energy credit procurements for each year
of the term of such contracts, which must have a
minimum tenure of 20 calendar years, the
procurement administrator, Agency, Commission
staff, and procurement monitor shall quantify the
annual cost of the contract by utilizing an
industry-standard, third-party forward price curve
for energy at the appropriate hub or load zone,
including the estimated magnitude and timing of
the price effects related to federal carbon
controls. Each forward price curve shall contain a
specific value of the forecasted market price of
electricity for each annual delivery year of the
contract. For procurement planning purposes, the
impact on the annual budget for the cost of
indexed renewable energy credits for each delivery
year shall be determined as the expected annual
contract expenditure for that year, equaling the

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difference between (i) the sum across all relevant
contracts of the applicable strike price
multiplied by contract quantity and (ii) the sum
across all relevant contracts of the forward price
curve for the applicable load zone for that year
multiplied by contract quantity. The contracting
utility shall not assume an obligation in excess
of the estimated annual cost of the contracts for
indexed renewable energy credits. Forward curves
shall be revised on an annual basis as updated
forward price curves are released and filed with
the Commission in the proceeding approving the
Agency's most recent long-term renewable resources
procurement plan. If the expected contract spend
is higher or lower than the total quantity of
contracts multiplied by the forward price curve
value for that year, the forward price curve shall
be updated by the procurement administrator, in
consultation with the Agency, Commission staff,
and procurement monitors, using then-currently
available price forecast data and additional
budget dollars shall be obligated or reobligated
as appropriate.
(4) To ensure that indexed renewable energy
credit prices remain predictable and affordable,
the Agency may consider the institution of a price

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collar on REC prices paid under indexed renewable
energy credit procurements establishing floor and
ceiling REC prices applicable to indexed REC
contract prices. Any price collars applicable to
indexed REC procurements shall be proposed by the
Agency through its long-term renewable resources
procurement plan.
(vi) All procurements under this subparagraph (G),
including the procurement of renewable energy credits
from hydropower facilities, shall comply with the
geographic requirements in subparagraph (I) of this
paragraph (1) and shall follow the procurement
processes and procedures described in this Section and
Section 16-111.5 of the Public Utilities Act to the
extent practicable, and these processes and procedures
may be expedited to accommodate the schedule
established by this subparagraph (G).
(vii) On and after the effective date of this
amendatory Act of the 103rd General Assembly, for all
procurements of renewable energy credits from
hydropower facilities, the Agency shall establish
contract terms designed to optimize existing
hydropower facilities through modernization or
retooling and establish new hydropower facilities at
existing dams. Procurements made under this item (vii)
shall prioritize projects located in designated

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environmental justice communities, as defined in
subsection (b) of Section 1-56 of this Act, or in
projects located in units of local government with
median incomes that do not exceed 82% of the median
income of the State.
(H) The procurement of renewable energy resources for
a given delivery year shall be reduced as described in
this subparagraph (H) if an alternative retail electric
supplier meets the requirements described in this
subparagraph (H).
(i) Within 45 days after June 1, 2017 (the
effective date of Public Act 99-906), an alternative
retail electric supplier or its successor shall submit
an informational filing to the Illinois Commerce
Commission certifying that, as of December 31, 2015,
the alternative retail electric supplier owned one or
more electric generating facilities that generates
renewable energy resources as defined in Section 1-10
of this Act, provided that such facilities are not
powered by wind or photovoltaics, and the facilities
generate one renewable energy credit for each
megawatthour of energy produced from the facility.
The informational filing shall identify each
facility that was eligible to satisfy the alternative
retail electric supplier's obligations under Section
16-115D of the Public Utilities Act as described in

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this item (i).
(ii) For a given delivery year, the alternative
retail electric supplier may elect to supply its
retail customers with renewable energy credits from
the facility or facilities described in item (i) of
this subparagraph (H) that continue to be owned by the
alternative retail electric supplier.
(iii) The alternative retail electric supplier
shall notify the Agency and the applicable utility, no
later than February 28 of the year preceding the
applicable delivery year or 15 days after June 1, 2017
(the effective date of Public Act 99-906), whichever
is later, of its election under item (ii) of this
subparagraph (H) to supply renewable energy credits to
retail customers of the utility. Such election shall
identify the amount of renewable energy credits to be
supplied by the alternative retail electric supplier
to the utility's retail customers and the source of
the renewable energy credits identified in the
informational filing as described in item (i) of this
subparagraph (H), subject to the following
limitations:
For the delivery year beginning June 1, 2018,
the maximum amount of renewable energy credits to
be supplied by an alternative retail electric
supplier under this subparagraph (H) shall be 68%

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

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

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annually publish a report on its website that
identifies the aggregate amount of renewable energy
credits supplied by alternative retail electric
suppliers under this subparagraph (H).
(I) The Agency shall design its long-term renewable
energy procurement plan to maximize the State's interest
in the health, safety, and welfare of its residents,
including but not limited to minimizing sulfur dioxide,
nitrogen oxide, particulate matter and other pollution
that adversely affects public health in this State,
increasing fuel and resource diversity in this State,
enhancing the reliability and resiliency of the
electricity distribution system in this State, meeting
goals to limit carbon dioxide emissions under federal or
State law, and contributing to a cleaner and healthier
environment for the citizens of this State. In order to
further these legislative purposes, renewable energy
credits shall be eligible to be counted toward the
renewable energy requirements of this subsection (c) if
they are generated from facilities located in this State.
The Agency may qualify renewable energy credits from
facilities located in states adjacent to Illinois or
renewable energy credits associated with the electricity
generated by a utility-scale wind energy facility or
utility-scale photovoltaic facility and transmitted by a
qualifying direct current project described in subsection

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(b-5) of Section 8-406 of the Public Utilities Act to a
delivery point on the electric transmission grid located
in this State or a state adjacent to Illinois, if the
generator demonstrates and the Agency determines that the
operation of such facility or facilities will help promote
the State's interest in the health, safety, and welfare of
its residents based on the public interest criteria
described above. For the purposes of this Section,
renewable resources that are delivered via a high voltage
direct current converter station located in Illinois shall
be deemed generated in Illinois at the time and location
the energy is converted to alternating current by the high
voltage direct current converter station if the high
voltage direct current transmission line: (i) after the
effective date of this amendatory Act of the 102nd General
Assembly, was constructed with a project labor agreement;
(ii) is capable of transmitting electricity at 525kv;
(iii) has an Illinois converter station located and
interconnected in the region of the PJM Interconnection,
LLC; (iv) does not operate as a public utility; and (v) if
the high voltage direct current transmission line was
energized after June 1, 2023. To ensure that the public
interest criteria are applied to the procurement and given
full effect, the Agency's long-term procurement plan shall
describe in detail how each public interest factor shall
be considered and weighted for facilities located in

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states adjacent to Illinois.
(J) In order to promote the competitive development of
renewable energy resources in furtherance of the State's
interest in the health, safety, and welfare of its
residents, renewable energy credits shall not be eligible
to be counted toward the renewable energy requirements of
this subsection (c) if they are sourced from a generating
unit whose costs were being recovered through rates
regulated by this State or any other state or states on or
after January 1, 2017. Each contract executed to purchase
renewable energy credits under this subsection (c) shall
provide for the contract's termination if the costs of the
generating unit supplying the renewable energy credits
subsequently begin to be recovered through rates regulated
by this State or any other state or states; and each
contract shall further provide that, in that event, the
supplier of the credits must return 110% of all payments
received under the contract. Amounts returned under the
requirements of this subparagraph (J) shall be retained by
the utility and all of these amounts shall be used for the
procurement of additional renewable energy credits from
new wind or new photovoltaic resources as defined in this
subsection (c). The long-term plan shall provide that
these renewable energy credits shall be procured in the
next procurement event.
Notwithstanding the limitations of this subparagraph

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(J), renewable energy credits sourced from generating
units that are constructed, purchased, owned, or leased by
an electric utility as part of an approved project,
program, or pilot under Section 1-56 of this Act shall be
eligible to be counted toward the renewable energy
requirements of this subsection (c), regardless of how the
costs of these units are recovered. As long as a
generating unit or an identifiable portion of a generating
unit has not had and does not have its costs recovered
through rates regulated by this State or any other state,
HVDC renewable energy credits associated with that
generating unit or identifiable portion thereof shall be
eligible to be counted toward the renewable energy
requirements of this subsection (c).
(K) The long-term renewable resources procurement plan
developed by the Agency in accordance with subparagraph
(A) of this paragraph (1) shall include an Adjustable
Block program for the procurement of renewable energy
credits from new photovoltaic projects that are
distributed renewable energy generation devices or new
photovoltaic community renewable generation projects. The
Adjustable Block program shall be generally designed to
provide for the steady, predictable, and sustainable
growth of new solar photovoltaic development in Illinois.
To this end, the Adjustable Block program shall provide a
transparent annual schedule of prices and quantities to

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enable the photovoltaic market to scale up and for
renewable energy credit prices to adjust at a predictable
rate over time. The prices set by the Adjustable Block
program can be reflected as a set value or as the product
of a formula.
The Adjustable Block program shall include for each
category of eligible projects for each delivery year: a
single block of nameplate capacity, a price for renewable
energy credits within that block, and the terms and
conditions for securing a spot on a waitlist once the
block is fully committed or reserved. Except as outlined
below, the waitlist of projects in a given year will carry
over to apply to the subsequent year when another block is
opened. Only projects energized on or after June 1, 2017
shall be eligible for the Adjustable Block program. For
each category for each delivery year the Agency shall
determine the amount of generation capacity in each block,
and the purchase price for each block, provided that the
purchase price provided and the total amount of generation
in all blocks for all categories shall be sufficient to
meet the goals in this subsection (c). The Agency shall
strive to issue a single block sized to provide for
stability and market growth. The Agency shall establish
program eligibility requirements that ensure that projects
that enter the program are sufficiently mature to indicate
a demonstrable path to completion. The Agency may

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periodically review its prior decisions establishing the
amount of generation capacity in each block, and the
purchase price for each block, and may propose, on an
expedited basis, changes to these previously set values,
including but not limited to redistributing these amounts
and the available funds as necessary and appropriate,
subject to Commission approval as part of the periodic
plan revision process described in Section 16-111.5 of the
Public Utilities Act. The Agency may define different
block sizes, purchase prices, or other distinct terms and
conditions for projects located in different utility
service territories if the Agency deems it necessary to
meet the goals in this subsection (c).
The Adjustable Block program shall include the
following categories in at least the following amounts:
(i) At least 20% from distributed renewable energy
generation devices with a nameplate capacity of no
more than 25 kilowatts.
(ii) At least 20% from distributed renewable
energy generation devices with a nameplate capacity of
more than 25 kilowatts and no more than 5,000
kilowatts. The Agency may create sub-categories within
this category to account for the differences between
projects for small commercial customers, large
commercial customers, and public or non-profit
customers.

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(iii) At least 30% from photovoltaic community
renewable generation projects. Capacity for this
category for the first 2 delivery years after the
effective date of this amendatory Act of the 102nd
General Assembly shall be allocated to waitlist
projects as provided in paragraph (3) of item (iv) of
subparagraph (G). Starting in the third delivery year
after the effective date of this amendatory Act of the
102nd General Assembly or earlier if the Agency
determines there is additional capacity needed for to
meet previous delivery year requirements, the
following shall apply:
(1) the Agency shall select projects on a
first-come, first-serve basis, however the Agency
may suggest additional methods to prioritize
projects that are submitted at the same time;
(2) projects shall have subscriptions of 25 kW
or less for at least 50% of the facility's
nameplate capacity and the Agency shall price the
renewable energy credits with that as a factor;
(3) projects shall not be colocated with one
or more other community renewable generation
projects, as defined in the Agency's first revised
long-term renewable resources procurement plan
approved by the Commission on February 18, 2020,
such that the aggregate nameplate capacity exceeds

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5,000 kilowatts; and
(4) projects greater than 2 MW may not apply
until after the approval of the Agency's revised
Long-Term Renewable Resources Procurement Plan
after the effective date of this amendatory Act of
the 102nd General Assembly.
(iv) At least 15% from distributed renewable
generation devices or photovoltaic community renewable
generation projects installed on public school land.
The Agency may create subcategories within this
category to account for the differences between
project size or location. Projects located within
environmental justice communities or within
Organizational Units that fall within Tier 1 or Tier 2
shall be given priority. Each of the Agency's periodic
updates to its long-term renewable resources
procurement plan to incorporate the procurement
described in this subparagraph (iv) shall also include
the proposed quantities or blocks, pricing, and
contract terms applicable to the procurement as
indicated herein. In each such update and procurement,
the Agency shall set the renewable energy credit price
and establish payment terms for the renewable energy
credits procured pursuant to this subparagraph (iv)
that make it feasible and affordable for public
schools to install photovoltaic distributed renewable

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energy devices on their premises, including, but not
limited to, those public schools subject to the
prioritization provisions of this subparagraph. For
the purposes of this item (iv):
"Environmental Justice Community" shall have the
same meaning set forth in the Agency's long-term
renewable resources procurement plan;
"Organization Unit", "Tier 1" and "Tier 2" shall
have the meanings set for in Section 18-8.15 of the
School Code;
"Public schools" shall have the meaning set forth
in Section 1-3 of the School Code and includes public
institutions of higher education, as defined in the
Board of Higher Education Act.
(v) At least 5% from community-driven community
solar projects intended to provide more direct and
tangible connection and benefits to the communities
which they serve or in which they operate and,
additionally, to increase the variety of community
solar locations, models, and options in Illinois. As
part of its long-term renewable resources procurement
plan, the Agency shall develop selection criteria for
projects participating in this category. Nothing in
this Section shall preclude the Agency from creating a
selection process that maximizes community ownership
and community benefits in selecting projects to

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receive renewable energy credits. Selection criteria
shall include:
(1) community ownership or community
wealth-building;
(2) additional direct and indirect community
benefit, beyond project participation as a
subscriber, including, but not limited to,
economic, environmental, social, cultural, and
physical benefits;
(3) meaningful involvement in project
organization and development by community members
or nonprofit organizations or public entities
located in or serving the community;
(4) engagement in project operations and
management by nonprofit organizations, public
entities, or community members; and
(5) whether a project is developed in response
to a site-specific RFP developed by community
members or a nonprofit organization or public
entity located in or serving the community.
Selection criteria may also prioritize projects
that:
(1) are developed in collaboration with or to
provide complementary opportunities for the Clean
Jobs Workforce Network Program, the Illinois
Climate Works Preapprenticeship Program, the

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Returning Residents Clean Jobs Training Program,
the Clean Energy Contractor Incubator Program, or
the Clean Energy Primes Contractor Accelerator
Program;
(2) increase the diversity of locations of
community solar projects in Illinois, including by
locating in urban areas and population centers;
(3) are located in Equity Investment Eligible
Communities;
(4) are not greenfield projects;
(5) serve only local subscribers;
(6) have a nameplate capacity that does not
exceed 500 kW;
(7) are developed by an equity eligible
contractor; or
(8) otherwise meaningfully advance the goals
of providing more direct and tangible connection
and benefits to the communities which they serve
or in which they operate and increasing the
variety of community solar locations, models, and
options in Illinois.
For the purposes of this item (v):
"Community" means a social unit in which people
come together regularly to effect change; a social
unit in which participants are marked by a cooperative
spirit, a common purpose, or shared interests or

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characteristics; or a space understood by its
residents to be delineated through geographic
boundaries or landmarks.
"Community benefit" means a range of services and
activities that provide affirmative, economic,
environmental, social, cultural, or physical value to
a community; or a mechanism that enables economic
development, high-quality employment, and education
opportunities for local workers and residents, or
formal monitoring and oversight structures such that
community members may ensure that those services and
activities respond to local knowledge and needs.
"Community ownership" means an arrangement in
which an electric generating facility is, or over time
will be, in significant part, owned collectively by
members of the community to which an electric
generating facility provides benefits; members of that
community participate in decisions regarding the
governance, operation, maintenance, and upgrades of
and to that facility; and members of that community
benefit from regular use of that facility.
Terms and guidance within these criteria that are
not defined in this item (v) shall be defined by the
Agency, with stakeholder input, during the development
of the Agency's long-term renewable resources
procurement plan. The Agency shall develop regular

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opportunities for projects to submit applications for
projects under this category, and develop selection
criteria that gives preference to projects that better
meet individual criteria as well as projects that
address a higher number of criteria.
(vi) At least 10% from distributed renewable
energy generation devices, which includes distributed
renewable energy devices with a nameplate capacity
under 5,000 kilowatts or photovoltaic community
renewable generation projects, from applicants that
are equity eligible contractors. The Agency may create
subcategories within this category to account for the
differences between project size and type. The Agency
shall propose to increase the percentage in this item
(vi) over time to 40% based on factors, including, but
not limited to, the number of equity eligible
contractors and capacity used in this item (vi) in
previous delivery years.
The Agency shall propose a payment structure for
contracts executed pursuant to this paragraph under
which, upon a demonstration of qualification or need,
applicant firms are advanced capital disbursed after
contract execution but before the contracted project's
energization. The amount or percentage of capital
advanced prior to project energization shall be
sufficient to both cover any increase in development

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costs resulting from prevailing wage requirements or
project-labor agreements, and designed to overcome
barriers in access to capital faced by equity eligible
contractors. The amount or percentage of advanced
capital may vary by subcategory within this category
and by an applicant's demonstration of need, with such
levels to be established through the Long-Term
Renewable Resources Procurement Plan authorized under
subparagraph (A) of paragraph (1) of subsection (c) of
this Section.
Contracts developed featuring capital advanced
prior to a project's energization shall feature
provisions to ensure both the successful development
of applicant projects and the delivery of the
renewable energy credits for the full term of the
contract, including ongoing collateral requirements
and other provisions deemed necessary by the Agency,
and may include energization timelines longer than for
comparable project types. The percentage or amount of
capital advanced prior to project energization shall
not operate to increase the overall contract value,
however contracts executed under this subparagraph may
feature renewable energy credit prices higher than
those offered to similar projects participating in
other categories. Capital advanced prior to
energization shall serve to reduce the ratable

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payments made after energization under items (ii) and
(iii) of subparagraph (L) or payments made for each
renewable energy credit delivery under item (iv) of
subparagraph (L).
(vii) The remaining capacity shall be allocated by
the Agency in order to respond to market demand. The
Agency shall allocate any discretionary capacity prior
to the beginning of each delivery year.
To the extent there is uncontracted capacity from any
block in any of categories (i) through (vi) at the end of a
delivery year, the Agency shall redistribute that capacity
to one or more other categories giving priority to
categories with projects on a waitlist. The redistributed
capacity shall be added to the annual capacity in the
subsequent delivery year, and the price for renewable
energy credits shall be the price for the new delivery
year. Redistributed capacity shall not be considered
redistributed when determining whether the goals in this
subsection (K) have been met.
Notwithstanding anything to the contrary, as the
Agency increases the capacity in item (vi) to 40% over
time, the Agency may reduce the capacity of items (i)
through (v) proportionate to the capacity of the
categories of projects in item (vi), to achieve a balance
of project types.
The Adjustable Block program shall be designed to

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ensure that renewable energy credits are procured from
projects in diverse locations and are not concentrated in
a few regional areas.
(L) Notwithstanding provisions for advancing capital
prior to project energization found in item (vi) of
subparagraph (K), the procurement of photovoltaic
renewable energy credits under items (i) through (vi) of
subparagraph (K) of this paragraph (1) shall otherwise be
subject to the following contract and payment terms:
(i) (Blank).
(ii) For those renewable energy credits that
qualify and are procured under item (i) of
subparagraph (K) of this paragraph (1), and any
similar category projects that are procured under item
(vi) of subparagraph (K) of this paragraph (1) that
qualify and are procured under item (vi), the contract
length shall be 15 years. The renewable energy credit
delivery contract value shall be paid in full, based
on the estimated generation during the first 15 years
of operation, by the contracting utilities at the time
that the facility producing the renewable energy
credits is interconnected at the distribution system
level of the utility and verified as energized and
compliant by the Program Administrator. The electric
utility shall receive and retire all renewable energy
credits generated by the project for the first 15

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years of operation. Renewable energy credits generated
by the project thereafter shall not be transferred
under the renewable energy credit delivery contract
with the counterparty electric utility.
(iii) For those renewable energy credits that
qualify and are procured under item (ii) and (v) of
subparagraph (K) of this paragraph (1) and any like
projects similar category that qualify and are
procured under item (vi), the contract length shall be
15 years. 15% of the renewable energy credit delivery
contract value, based on the estimated generation
during the first 15 years of operation, shall be paid
by the contracting utilities at the time that the
facility producing the renewable energy credits is
interconnected at the distribution system level of the
utility and verified as energized and compliant by the
Program Administrator. The remaining portion shall be
paid ratably over the subsequent 6-year period. The
electric utility shall receive and retire all
renewable energy credits generated by the project for
the first 15 years of operation. Renewable energy
credits generated by the project thereafter shall not
be transferred under the renewable energy credit
delivery contract with the counterparty electric
utility.
(iv) For those renewable energy credits that

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qualify and are procured under items (iii) and (iv) of
subparagraph (K) of this paragraph (1), and any like
projects that qualify and are procured under item
(vi), the renewable energy credit delivery contract
length shall be 20 years and shall be paid over the
delivery term, not to exceed during each delivery year
the contract price multiplied by the estimated annual
renewable energy credit generation amount. If
generation of renewable energy credits during a
delivery year exceeds the estimated annual generation
amount, the excess renewable energy credits shall be
carried forward to future delivery years and shall not
expire during the delivery term. If generation of
renewable energy credits during a delivery year,
including carried forward excess renewable energy
credits, if any, is less than the estimated annual
generation amount, payments during such delivery year
will not exceed the quantity generated plus the
quantity carried forward multiplied by the contract
price. The electric utility shall receive all
renewable energy credits generated by the project
during the first 20 years of operation and retire all
renewable energy credits paid for under this item (iv)
and return at the end of the delivery term all
renewable energy credits that were not paid for.
Renewable energy credits generated by the project

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thereafter shall not be transferred under the
renewable energy credit delivery contract with the
counterparty electric utility. Notwithstanding the
preceding, for those projects participating under item
(iii) of subparagraph (K), the contract price for a
delivery year shall be based on subscription levels as
measured on the higher of the first business day of the
delivery year or the first business day 6 months after
the first business day of the delivery year.
Subscription of 90% of nameplate capacity or greater
shall be deemed to be fully subscribed for the
purposes of this item (iv). For projects receiving a
20-year delivery contract, REC prices shall be
adjusted downward for consistency with the incentive
levels previously determined to be necessary to
support projects under 15-year delivery contracts,
taking into consideration any additional new
requirements placed on the projects, including, but
not limited to, labor standards.
(v) Each contract shall include provisions to
ensure the delivery of the estimated quantity of
renewable energy credits and ongoing collateral
requirements and other provisions deemed appropriate
by the Agency.
(vi) The utility shall be the counterparty to the
contracts executed under this subparagraph (L) that

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are approved by the Commission under the process
described in Section 16-111.5 of the Public Utilities
Act. No contract shall be executed for an amount that
is less than one renewable energy credit per year.
(vii) If, at any time, approved applications for
the Adjustable Block program exceed funds collected by
the electric utility or would cause the Agency to
exceed the limitation described in subparagraph (E) of
this paragraph (1) on the amount of renewable energy
resources that may be procured, then the Agency may
consider future uncommitted funds to be reserved for
these contracts on a first-come, first-served basis.
(viii) Nothing in this Section shall require the
utility to advance any payment or pay any amounts that
exceed the actual amount of revenues anticipated to be
collected by the utility under paragraph (6) of this
subsection (c) and subsection (k) of Section 16-108 of
the Public Utilities Act inclusive of eligible funds
collected in prior years and alternative compliance
payments for use by the utility.
(ix) Notwithstanding other requirements of this
subparagraph (L), no modification shall be required to
Adjustable Block program contracts if they were
already executed prior to the establishment, approval,
and implementation of new contract forms as a result
of this amendatory Act of the 102nd General Assembly.

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(x) Contracts may be assignable, but only to
entities first deemed by the Agency to have met
program terms and requirements applicable to direct
program participation. In developing contracts for the
delivery of renewable energy credits, the Agency shall
be permitted to establish fees applicable to each
contract assignment.
(M) The Agency shall be authorized to retain one or
more experts or expert consulting firms to develop,
administer, implement, operate, and evaluate the
Adjustable Block program described in subparagraph (K) of
this paragraph (1), and the Agency shall retain the
consultant or consultants in the same manner, to the
extent practicable, as the Agency retains others to
administer provisions of this Act, including, but not
limited to, the procurement administrator. The selection
of experts and expert consulting firms and the procurement
process described in this subparagraph (M) are exempt from
the requirements of Section 20-10 of the Illinois
Procurement Code, under Section 20-10 of that Code. The
Agency shall strive to minimize administrative expenses in
the implementation of the Adjustable Block program.
The Program Administrator may charge application fees
to participating firms to cover the cost of program
administration. Any application fee amounts shall
initially be determined through the long-term renewable

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resources procurement plan, and modifications to any
application fee that deviate more than 25% from the
Commission's approved value must be approved by the
Commission as a long-term plan revision under Section
16-111.5 of the Public Utilities Act. The Agency shall
consider stakeholder feedback when making adjustments to
application fees and shall notify stakeholders in advance
of any planned changes.
In addition to covering the costs of program
administration, the Agency, in conjunction with its
Program Administrator, may also use the proceeds of such
fees charged to participating firms to support public
education and ongoing regional and national coordination
with nonprofit organizations, public bodies, and others
engaged in the implementation of renewable energy
incentive programs or similar initiatives. This work may
include developing papers and reports, hosting regional
and national conferences, and other work deemed necessary
by the Agency to position the State of Illinois as a
national leader in renewable energy incentive program
development and administration.
The Agency and its consultant or consultants shall
monitor block activity, share program activity with
stakeholders and conduct quarterly meetings to discuss
program activity and market conditions. If necessary, the
Agency may make prospective administrative adjustments to

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the Adjustable Block program design, such as making
adjustments to purchase prices as necessary to achieve the
goals of this subsection (c). Program modifications to any
block price that do not deviate from the Commission's
approved value by more than 10% shall take effect
immediately and are not subject to Commission review and
approval. Program modifications to any block price that
deviate more than 10% from the Commission's approved value
must be approved by the Commission as a long-term plan
amendment under Section 16-111.5 of the Public Utilities
Act. The Agency shall consider stakeholder feedback when
making adjustments to the Adjustable Block design and
shall notify stakeholders in advance of any planned
changes.
The Agency and its program administrators for both the
Adjustable Block program and the Illinois Solar for All
Program, consistent with the requirements of this
subsection (c) and subsection (b) of Section 1-56 of this
Act, shall propose the Adjustable Block program terms,
conditions, and requirements, including the prices to be
paid for renewable energy credits, where applicable, and
requirements applicable to participating entities and
project applications, through the development, review, and
approval of the Agency's long-term renewable resources
procurement plan described in this subsection (c) and
paragraph (5) of subsection (b) of Section 16-111.5 of the

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Public Utilities Act. Terms, conditions, and requirements
for program participation shall include the following:
(i) The Agency shall establish a registration
process for entities seeking to qualify for
program-administered incentive funding and establish
baseline qualifications for vendor approval. The
Agency must maintain a list of approved entities on
each program's website, and may revoke a vendor's
ability to receive program-administered incentive
funding status upon a determination that the vendor
failed to comply with contract terms, the law, or
other program requirements.
(ii) The Agency shall establish program
requirements and minimum contract terms to ensure
projects are properly installed and produce their
expected amounts of energy. Program requirements may
include on-site inspections and photo documentation of
projects under construction. The Agency may require
repairs, alterations, or additions to remedy any
material deficiencies discovered. Vendors who have a
disproportionately high number of deficient systems
may lose their eligibility to continue to receive
State-administered incentive funding through Agency
programs and procurements.
(iii) To discourage deceptive marketing or other
bad faith business practices, the Agency may require

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direct program participants, including agents
operating on their behalf, to provide standardized
disclosures to a customer prior to that customer's
execution of a contract for the development of a
distributed generation system or a subscription to a
community solar project.
(iv) The Agency shall establish one or multiple
Consumer Complaints Centers to accept complaints
regarding businesses that participate in, or otherwise
benefit from, State-administered incentive funding
through Agency-administered programs. The Agency shall
maintain a public database of complaints with any
confidential or particularly sensitive information
redacted from public entries.
(v) Through a filing in the proceeding for the
approval of its long-term renewable energy resources
procurement plan, the Agency shall provide an annual
written report to the Illinois Commerce Commission
documenting the frequency and nature of complaints and
any enforcement actions taken in response to those
complaints.
(vi) The Agency shall schedule regular meetings
with representatives of the Office of the Attorney
General, the Illinois Commerce Commission, consumer
protection groups, and other interested stakeholders
to share relevant information about consumer

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protection, project compliance, and complaints
received.
(vii) To the extent that complaints received
implicate the jurisdiction of the Office of the
Attorney General, the Illinois Commerce Commission, or
local, State, or federal law enforcement, the Agency
shall also refer complaints to those entities as
appropriate.
(N) The Agency shall establish the terms, conditions,
and program requirements for photovoltaic community
renewable generation projects with a goal to expand access
to a broader group of energy consumers, to ensure robust
participation opportunities for residential and small
commercial customers and those who cannot install
renewable energy on their own properties. Subject to
reasonable limitations, any plan approved by the
Commission shall allow subscriptions to community
renewable generation projects to be portable and
transferable. For purposes of this subparagraph (N),
"portable" means that subscriptions may be retained by the
subscriber even if the subscriber relocates or changes its
address within the same utility service territory; and
"transferable" means that a subscriber may assign or sell
subscriptions to another person within the same utility
service territory.
Through the development of its long-term renewable

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resources procurement plan, the Agency may consider
whether community renewable generation projects utilizing
technologies other than photovoltaics should be supported
through State-administered incentive funding, and may
issue requests for information to gauge market demand.
Electric utilities shall provide a monetary credit to
a subscriber's subsequent bill for service for the
proportional output of a community renewable generation
project attributable to that subscriber as specified in
Section 16-107.5 of the Public Utilities Act.
The Agency shall purchase renewable energy credits
from subscribed shares of photovoltaic community renewable
generation projects through the Adjustable Block program
described in subparagraph (K) of this paragraph (1) or
through the Illinois Solar for All Program described in
Section 1-56 of this Act. The electric utility shall
purchase any unsubscribed energy from community renewable
generation projects that are Qualifying Facilities ("QF")
under the electric utility's tariff for purchasing the
output from QFs under Public Utilities Regulatory Policies
Act of 1978.
The owners of and any subscribers to a community
renewable generation project shall not be considered
public utilities or alternative retail electricity
suppliers under the Public Utilities Act solely as a
result of their interest in or subscription to a community

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renewable generation project and shall not be required to
become an alternative retail electric supplier by
participating in a community renewable generation project
with a public utility.
(O) For the delivery year beginning June 1, 2018, the
long-term renewable resources procurement plan required by
this subsection (c) shall provide for the Agency to
procure contracts to continue offering the Illinois Solar
for All Program described in subsection (b) of Section
1-56 of this Act, and the contracts approved by the
Commission shall be executed by the utilities that are
subject to this subsection (c). The long-term renewable
resources procurement plan shall allocate up to
$50,000,000 per delivery year to fund the programs, and
the plan shall determine the amount of funding to be
apportioned to the programs identified in subsection (b)
of Section 1-56 of this Act; provided that for the
delivery years beginning June 1, 2021, June 1, 2022, and
June 1, 2023, the long-term renewable resources
procurement plan may average the annual budgets over a
3-year period to account for program ramp-up. For the
delivery years beginning June 1, 2021, June 1, 2024, June
1, 2027, and June 1, 2030 and additional $10,000,000 shall
be provided to the Department of Commerce and Economic
Opportunity to implement the workforce development
programs and reporting as outlined in Section 16-108.12 of

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the Public Utilities Act. In making the determinations
required under this subparagraph (O), the Commission shall
consider the experience and performance under the programs
and any evaluation reports. The Commission shall also
provide for an independent evaluation of those programs on
a periodic basis that are funded under this subparagraph
(O).
(P) All programs and procurements under this
subsection (c) shall be designed to encourage
participating projects to use a diverse and equitable
workforce and a diverse set of contractors, including
minority-owned businesses, disadvantaged businesses,
trade unions, graduates of any workforce training programs
administered under this Act, and small businesses.
The Agency shall develop a method to optimize
procurement of renewable energy credits from proposed
utility-scale projects that are located in communities
eligible to receive Energy Transition Community Grants
pursuant to Section 10-20 of the Energy Community
Reinvestment Act. If this requirement conflicts with other
provisions of law or the Agency determines that full
compliance with the requirements of this subparagraph (P)
would be unreasonably costly or administratively
impractical, the Agency is to propose alternative
approaches to achieve development of renewable energy
resources in communities eligible to receive Energy

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Transition Community Grants pursuant to Section 10-20 of
the Energy Community Reinvestment Act or seek an exemption
from this requirement from the Commission.
(Q) Each facility listed in subitems (i) through (ix)
of item (1) of this subparagraph (Q) for which a renewable
energy credit delivery contract is signed after the
effective date of this amendatory Act of the 102nd General
Assembly is subject to the following requirements through
the Agency's long-term renewable resources procurement
plan:
(1) Each facility shall be subject to the
prevailing wage requirements included in the
Prevailing Wage Act. The Agency shall require
verification that all construction performed on the
facility by the renewable energy credit delivery
contract holder, its contractors, or its
subcontractors relating to construction of the
facility is performed by construction employees
receiving an amount for that work equal to or greater
than the general prevailing rate, as that term is
defined in Section 3 of the Prevailing Wage Act. For
purposes of this item (1), "house of worship" means
property that is both (1) used exclusively by a
religious society or body of persons as a place for
religious exercise or religious worship and (2)
recognized as exempt from taxation pursuant to Section

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15-40 of the Property Tax Code. This item (1) shall
apply to any the following:
(i) all new utility-scale wind projects;
(ii) all new utility-scale photovoltaic
projects and repowered wind projects;
(iii) all new brownfield photovoltaic
projects;
(iv) all new photovoltaic community renewable
energy facilities that qualify for item (iii) of
subparagraph (K) of this paragraph (1);
(v) all new community driven community
photovoltaic projects that qualify for item (v) of
subparagraph (K) of this paragraph (1);
(vi) all new photovoltaic projects on public
school land that qualify for item (iv) of
subparagraph (K) of this paragraph (1);
(vii) all new photovoltaic distributed
renewable energy generation devices that (1)
qualify for item (i) of subparagraph (K) of this
paragraph (1); (2) are not projects that serve
single-family or multi-family residential
buildings; and (3) are not houses of worship where
the aggregate capacity including collocated
projects would not exceed 100 kilowatts;
(viii) all new photovoltaic distributed
renewable energy generation devices that (1)

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qualify for item (ii) of subparagraph (K) of this
paragraph (1); (2) are not projects that serve
single-family or multi-family residential
buildings; and (3) are not houses of worship where
the aggregate capacity including collocated
projects would not exceed 100 kilowatts;
(ix) all new, modernized, or retooled
hydropower facilities.
(2) Renewable energy credits procured from new
utility-scale wind projects, new utility-scale solar
projects, new brownfield solar projects, repowered
wind projects, and retooled hydropower facilities
pursuant to Agency procurement events occurring after
the effective date of this amendatory Act of the 102nd
General Assembly must be from facilities built by
general contractors that must enter into a project
labor agreement, as defined by this Act, prior to
construction. The project labor agreement shall be
filed with the Director in accordance with procedures
established by the Agency through its long-term
renewable resources procurement plan. Any information
submitted to the Agency in this item (2) shall be
considered commercially sensitive information. At a
minimum, the project labor agreement must provide the
names, addresses, and occupations of the owner of the
plant and the individuals representing the labor

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organization employees participating in the project
labor agreement consistent with the Project Labor
Agreements Act. The agreement must also specify the
terms and conditions as defined by this Act.
(3) It is the intent of this Section to ensure that
economic development occurs across Illinois
communities, that emerging businesses may grow, and
that there is improved access to the clean energy
economy by persons who have greater economic burdens
to success. The Agency shall take into consideration
the unique cost of compliance of this subparagraph (Q)
that might be borne by equity eligible contractors,
shall include such costs when determining the price of
renewable energy credits in the Adjustable Block
program, and shall take such costs into consideration
in a nondiscriminatory manner when comparing bids for
competitive procurements. The Agency shall consider
costs associated with compliance whether in the
development, financing, or construction of projects.
The Agency shall periodically review the assumptions
in these costs and may adjust prices, in compliance
with subparagraph (M) of this paragraph (1).
(R) In its long-term renewable resources procurement
plan, the Agency shall establish a self-direct renewable
portfolio standard compliance program for eligible
self-direct customers that purchase renewable energy

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credits from utility-scale wind and solar projects through
long-term agreements for purchase of renewable energy
credits as described in this Section. Such long-term
agreements may include the purchase of energy or other
products on a physical or financial basis and may involve
an alternative retail electric supplier as defined in
Section 16-102 of the Public Utilities Act. This program
shall take effect in the delivery year commencing June 1,
2023.
(1) For the purposes of this subparagraph:
"Eligible self-direct customer" means any retail
customers of an electric utility that serves 3,000,000
or more retail customers in the State and whose total
highest 30-minute demand was more than 10,000
kilowatts, or any retail customers of an electric
utility that serves less than 3,000,000 retail
customers but more than 500,000 retail customers in
the State and whose total highest 15-minute demand was
more than 10,000 kilowatts.
"Retail customer" has the meaning set forth in
Section 16-102 of the Public Utilities Act and
multiple retail customer accounts under the same
corporate parent may aggregate their account demands
to meet the 10,000 kilowatt threshold. The criteria
for determining whether this subparagraph is
applicable to a retail customer shall be based on the

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12 consecutive billing periods prior to the start of
the year in which the application is filed.
(2) For renewable energy credits to count toward
the self-direct renewable portfolio standard
compliance program, they must:
(i) qualify as renewable energy credits as
defined in Section 1-10 of this Act;
(ii) be sourced from one or more renewable
energy generating facilities that comply with the
geographic requirements as set forth in
subparagraph (I) of paragraph (1) of subsection
(c) as interpreted through the Agency's long-term
renewable resources procurement plan, or, where
applicable, the geographic requirements that
governed utility-scale renewable energy credits at
the time the eligible self-direct customer entered
into the applicable renewable energy credit
purchase agreement;
(iii) be procured through long-term contracts
with term lengths of at least 10 years either
directly with the renewable energy generating
facility or through a bundled power purchase
agreement, a virtual power purchase agreement, an
agreement between the renewable generating
facility, an alternative retail electric supplier,
and the customer, or such other structure as is

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permissible under this subparagraph (R);
(iv) be equivalent in volume to at least 40%
of the eligible self-direct customer's usage,
determined annually by the eligible self-direct
customer's usage during the previous delivery
year, measured to the nearest megawatt-hour;
(v) be retired by or on behalf of the large
energy customer;
(vi) be sourced from new utility-scale wind
projects or new utility-scale solar projects; and
(vii) if the contracts for renewable energy
credits are entered into after the effective date
of this amendatory Act of the 102nd General
Assembly, the new utility-scale wind projects or
new utility-scale solar projects must comply with
the requirements established in subparagraphs (P)
and (Q) of paragraph (1) of this subsection (c)
and subsection (c-10).
(3) The self-direct renewable portfolio standard
compliance program shall be designed to allow eligible
self-direct customers to procure new renewable energy
credits from new utility-scale wind projects or new
utility-scale photovoltaic projects. The Agency shall
annually determine the amount of utility-scale
renewable energy credits it will include each year
from the self-direct renewable portfolio standard

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compliance program, subject to receiving qualifying
applications. In making this determination, the Agency
shall evaluate publicly available analyses and studies
of the potential market size for utility-scale
renewable energy long-term purchase agreements by
commercial and industrial energy customers and make
that report publicly available. If demand for
participation in the self-direct renewable portfolio
standard compliance program exceeds availability, the
Agency shall ensure participation is evenly split
between commercial and industrial users to the extent
there is sufficient demand from both customer classes.
Each renewable energy credit procured pursuant to this
subparagraph (R) by a self-direct customer shall
reduce the total volume of renewable energy credits
the Agency is otherwise required to procure from new
utility-scale projects pursuant to subparagraph (C) of
paragraph (1) of this subsection (c) on behalf of
contracting utilities where the eligible self-direct
customer is located. The self-direct customer shall
file an annual compliance report with the Agency
pursuant to terms established by the Agency through
its long-term renewable resources procurement plan to
be eligible for participation in this program.
Customers must provide the Agency with their most
recent electricity billing statements or other

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information deemed necessary by the Agency to
demonstrate they are an eligible self-direct customer.
(4) The Commission shall approve a reduction in
the volumetric charges collected pursuant to Section
16-108 of the Public Utilities Act for approved
eligible self-direct customers equivalent to the
anticipated cost of renewable energy credit deliveries
under contracts for new utility-scale wind and new
utility-scale solar entered for each delivery year
after the large energy customer begins retiring
eligible new utility scale renewable energy credits
for self-compliance. The self-direct credit amount
shall be determined annually and is equal to the
estimated portion of the cost authorized by
subparagraph (E) of paragraph (1) of this subsection
(c) that supported the annual procurement of
utility-scale renewable energy credits in the prior
delivery year using a methodology described in the
long-term renewable resources procurement plan,
expressed on a per kilowatthour basis, and does not
include (i) costs associated with any contracts
entered into before the delivery year in which the
customer files the initial compliance report to be
eligible for participation in the self-direct program,
and (ii) costs associated with procuring renewable
energy credits through existing and future contracts

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through the Adjustable Block Program, subsection (c-5)
of this Section 1-75, and the Solar for All Program.
The Agency shall assist the Commission in determining
the current and future costs. The Agency must
determine the self-direct credit amount for new and
existing eligible self-direct customers and submit
this to the Commission in an annual compliance filing.
The Commission must approve the self-direct credit
amount by June 1, 2023 and June 1 of each delivery year
thereafter.
(5) Customers described in this subparagraph (R)
shall apply, on a form developed by the Agency, to the
Agency to be designated as a self-direct eligible
customer. Once the Agency determines that a
self-direct customer is eligible for participation in
the program, the self-direct customer will remain
eligible until the end of the term of the contract.
Thereafter, application may be made not less than 12
months before the filing date of the long-term
renewable resources procurement plan described in this
Act. At a minimum, such application shall contain the
following:
(i) the customer's certification that, at the
time of the customer's application, the customer
qualifies to be a self-direct eligible customer,
including documents demonstrating that

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qualification;
(ii) the customer's certification that the
customer has entered into or will enter into by
the beginning of the applicable procurement year,
one or more bilateral contracts for new wind
projects or new photovoltaic projects, including
supporting documentation;
(iii) certification that the contract or
contracts for new renewable energy resources are
long-term contracts with term lengths of at least
10 years, including supporting documentation;
(iv) certification of the quantities of
renewable energy credits that the customer will
purchase each year under such contract or
contracts, including supporting documentation;
(v) proof that the contract is sufficient to
produce renewable energy credits to be equivalent
in volume to at least 40% of the large energy
customer's usage from the previous delivery year,
measured to the nearest megawatt-hour; and
(vi) certification that the customer intends
to maintain the contract for the duration of the
length of the contract.
(6) If a customer receives the self-direct credit
but fails to properly procure and retire renewable
energy credits as required under this subparagraph

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(R), the Commission, on petition from the Agency and
after notice and hearing, may direct such customer's
utility to recover the cost of the wrongfully received
self-direct credits plus interest through an adder to
charges assessed pursuant to Section 16-108 of the
Public Utilities Act. Self-direct customers who
knowingly fail to properly procure and retire
renewable energy credits and do not notify the Agency
are ineligible for continued participation in the
self-direct renewable portfolio standard compliance
program.
(2) (Blank).
(3) (Blank).
(4) The electric utility shall retire all renewable
energy credits used to comply with the standard.
(5) Beginning with the 2010 delivery year and ending
June 1, 2017, an electric utility subject to this
subsection (c) shall apply the lesser of the maximum
alternative compliance payment rate or the most recent
estimated alternative compliance payment rate for its
service territory for the corresponding compliance period,
established pursuant to subsection (d) of Section 16-115D
of the Public Utilities Act to its retail customers that
take service pursuant to the electric utility's hourly
pricing tariff or tariffs. The electric utility shall
retain all amounts collected as a result of the

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application of the alternative compliance payment rate or
rates to such customers, and, beginning in 2011, the
utility shall include in the information provided under
item (1) of subsection (d) of Section 16-111.5 of the
Public Utilities Act the amounts collected under the
alternative compliance payment rate or rates for the prior
year ending May 31. Notwithstanding any limitation on the
procurement of renewable energy resources imposed by item
(2) of this subsection (c), the Agency shall increase its
spending on the purchase of renewable energy resources to
be procured by the electric utility for the next plan year
by an amount equal to the amounts collected by the utility
under the alternative compliance payment rate or rates in
the prior year ending May 31.
(6) The electric utility shall be entitled to recover
all of its costs associated with the procurement of
renewable energy credits under plans approved under this
Section and Section 16-111.5 of the Public Utilities Act.
These costs shall include associated reasonable expenses
for implementing the procurement programs, including, but
not limited to, the costs of administering and evaluating
the Adjustable Block program, through an automatic
adjustment clause tariff in accordance with subsection (k)
of Section 16-108 of the Public Utilities Act.
(7) Renewable energy credits procured from new
photovoltaic projects or new distributed renewable energy

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generation devices under this Section after June 1, 2017
(the effective date of Public Act 99-906) must be procured
from devices installed by a qualified person in compliance
with the requirements of Section 16-128A of the Public
Utilities Act and any rules or regulations adopted
thereunder.
In meeting the renewable energy requirements of this
subsection (c), to the extent feasible and consistent with
State and federal law, the renewable energy credit
procurements, Adjustable Block solar program, and
community renewable generation program shall provide
employment opportunities for all segments of the
population and workforce, including minority-owned and
female-owned business enterprises, and shall not,
consistent with State and federal law, discriminate based
on race or socioeconomic status.
(c-5) Procurement of renewable energy credits from new
renewable energy facilities installed at or adjacent to the
sites of electric generating facilities that burn or burned
coal as their primary fuel source.
(1) In addition to the procurement of renewable energy
credits pursuant to long-term renewable resources
procurement plans in accordance with subsection (c) of
this Section and Section 16-111.5 of the Public Utilities
Act, the Agency shall conduct procurement events in
accordance with this subsection (c-5) for the procurement

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by electric utilities that served more than 300,000 retail
customers in this State as of January 1, 2019 of renewable
energy credits from new renewable energy facilities to be
installed at or adjacent to the sites of electric
generating facilities that, as of January 1, 2016, burned
coal as their primary fuel source and meet the other
criteria specified in this subsection (c-5). For purposes
of this subsection (c-5), "new renewable energy facility"
means a new utility-scale solar project as defined in this
Section 1-75. The renewable energy credits procured
pursuant to this subsection (c-5) may be included or
counted for purposes of compliance with the amounts of
renewable energy credits required to be procured pursuant
to subsection (c) of this Section to the extent that there
are otherwise shortfalls in compliance with such
requirements. The procurement of renewable energy credits
by electric utilities pursuant to this subsection (c-5)
shall be funded solely by revenues collected from the Coal
to Solar and Energy Storage Initiative Charge provided for
in this subsection (c-5) and subsection (i-5) of Section
16-108 of the Public Utilities Act, shall not be funded by
revenues collected through any of the other funding
mechanisms provided for in subsection (c) of this Section,
and shall not be subject to the limitation imposed by
subsection (c) on charges to retail customers for costs to
procure renewable energy resources pursuant to subsection

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(c), and shall not be subject to any other requirements or
limitations of subsection (c).
(2) The Agency shall conduct 2 procurement events to
select owners of electric generating facilities meeting
the eligibility criteria specified in this subsection
(c-5) to enter into long-term contracts to sell renewable
energy credits to electric utilities serving more than
300,000 retail customers in this State as of January 1,
2019. The first procurement event shall be conducted no
later than March 31, 2022, unless the Agency elects to
delay it, until no later than May 1, 2022, due to its
overall volume of work, and shall be to select owners of
electric generating facilities located in this State and
south of federal Interstate Highway 80 that meet the
eligibility criteria specified in this subsection (c-5).
The second procurement event shall be conducted no sooner
than September 30, 2022 and no later than October 31, 2022
and shall be to select owners of electric generating
facilities located anywhere in this State that meet the
eligibility criteria specified in this subsection (c-5).
The Agency shall establish and announce a time period,
which shall begin no later than 30 days prior to the
scheduled date for the procurement event, during which
applicants may submit applications to be selected as
suppliers of renewable energy credits pursuant to this
subsection (c-5). The eligibility criteria for selection

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as a supplier of renewable energy credits pursuant to this
subsection (c-5) shall be as follows:
(A) The applicant owns an electric generating
facility located in this State that: (i) as of January
1, 2016, burned coal as its primary fuel to generate
electricity; and (ii) has, or had prior to retirement,
an electric generating capacity of at least 150
megawatts. The electric generating facility can be
either: (i) retired as of the date of the procurement
event; or (ii) still operating as of the date of the
procurement event.
(B) The applicant is not (i) an electric
cooperative as defined in Section 3-119 of the Public
Utilities Act, or (ii) an entity described in
subsection (b)(1) of Section 3-105 of the Public
Utilities Act, or an association or consortium of or
an entity owned by entities described in (i) or (ii);
and the coal-fueled electric generating facility was
at one time owned, in whole or in part, by a public
utility as defined in Section 3-105 of the Public
Utilities Act.
(C) If participating in the first procurement
event, the applicant proposes and commits to construct
and operate, at the site, and if necessary for
sufficient space on property adjacent to the existing
property, at which the electric generating facility

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identified in paragraph (A) is located: (i) a new
renewable energy facility of at least 20 megawatts but
no more than 100 megawatts of electric generating
capacity, and (ii) an energy storage facility having a
storage capacity equal to at least 2 megawatts and at
most 10 megawatts. If participating in the second
procurement event, the applicant proposes and commits
to construct and operate, at the site, and if
necessary for sufficient space on property adjacent to
the existing property, at which the electric
generating facility identified in paragraph (A) is
located: (i) a new renewable energy facility of at
least 5 megawatts but no more than 20 megawatts of
electric generating capacity, and (ii) an energy
storage facility having a storage capacity equal to at
least 0.5 megawatts and at most one megawatt.
(D) The applicant agrees that the new renewable
energy facility and the energy storage facility will
be constructed or installed by a qualified entity or
entities in compliance with the requirements of
subsection (g) of Section 16-128A of the Public
Utilities Act and any rules adopted thereunder.
(E) The applicant agrees that personnel operating
the new renewable energy facility and the energy
storage facility will have the requisite skills,
knowledge, training, experience, and competence, which

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may be demonstrated by completion or current
participation and ultimate completion by employees of
an accredited or otherwise recognized apprenticeship
program for the employee's particular craft, trade, or
skill, including through training and education
courses and opportunities offered by the owner to
employees of the coal-fueled electric generating
facility or by previous employment experience
performing the employee's particular work skill or
function.
(F) The applicant commits that not less than the
prevailing wage, as determined pursuant to the
Prevailing Wage Act, will be paid to the applicant's
employees engaged in construction activities
associated with the new renewable energy facility and
the new energy storage facility and to the employees
of applicant's contractors engaged in construction
activities associated with the new renewable energy
facility and the new energy storage facility, and
that, on or before the commercial operation date of
the new renewable energy facility, the applicant shall
file a report with the Agency certifying that the
requirements of this subparagraph (F) have been met.
(G) The applicant commits that if selected, it
will negotiate a project labor agreement for the
construction of the new renewable energy facility and

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associated energy storage facility that includes
provisions requiring the parties to the agreement to
work together to establish diversity threshold
requirements and to ensure best efforts to meet
diversity targets, improve diversity at the applicable
job site, create diverse apprenticeship opportunities,
and create opportunities to employ former coal-fired
power plant workers.
(H) The applicant commits to enter into a contract
or contracts for the applicable duration to provide
specified numbers of renewable energy credits each
year from the new renewable energy facility to
electric utilities that served more than 300,000
retail customers in this State as of January 1, 2019,
at a price of $30 per renewable energy credit. The
price per renewable energy credit shall be fixed at
$30 for the applicable duration and the renewable
energy credits shall not be indexed renewable energy
credits as provided for in item (v) of subparagraph
(G) of paragraph (1) of subsection (c) of Section 1-75
of this Act. The applicable duration of each contract
shall be 20 years, unless the applicant is physically
interconnected to the PJM Interconnection, LLC
transmission grid and had a generating capacity of at
least 1,200 megawatts as of January 1, 2021, in which
case the applicable duration of the contract shall be

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15 years.
(I) The applicant's application is certified by an
officer of the applicant and by an officer of the
applicant's ultimate parent company, if any.
(3) An applicant may submit applications to contract
to supply renewable energy credits from more than one new
renewable energy facility to be constructed at or adjacent
to one or more qualifying electric generating facilities
owned by the applicant. The Agency may select new
renewable energy facilities to be located at or adjacent
to the sites of more than one qualifying electric
generation facility owned by an applicant to contract with
electric utilities to supply renewable energy credits from
such facilities.
(4) The Agency shall assess fees to each applicant to
recover the Agency's costs incurred in receiving and
evaluating applications, conducting the procurement event,
developing contracts for sale, delivery and purchase of
renewable energy credits, and monitoring the
administration of such contracts, as provided for in this
subsection (c-5), including fees paid to a procurement
administrator retained by the Agency for one or more of
these purposes.
(5) The Agency shall select the applicants and the new
renewable energy facilities to contract with electric
utilities to supply renewable energy credits in accordance

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with this subsection (c-5). In the first procurement
event, the Agency shall select applicants and new
renewable energy facilities to supply renewable energy
credits, at a price of $30 per renewable energy credit,
aggregating to no less than 400,000 renewable energy
credits per year for the applicable duration, assuming
sufficient qualifying applications to supply, in the
aggregate, at least that amount of renewable energy
credits per year; and not more than 580,000 renewable
energy credits per year for the applicable duration. In
the second procurement event, the Agency shall select
applicants and new renewable energy facilities to supply
renewable energy credits, at a price of $30 per renewable
energy credit, aggregating to no more than 625,000
renewable energy credits per year less the amount of
renewable energy credits each year contracted for as a
result of the first procurement event, for the applicable
durations. The number of renewable energy credits to be
procured as specified in this paragraph (5) shall not be
reduced based on renewable energy credits procured in the
self-direct renewable energy credit compliance program
established pursuant to subparagraph (R) of paragraph (1)
of subsection (c) of Section 1-75.
(6) The obligation to purchase renewable energy
credits from the applicants and their new renewable energy
facilities selected by the Agency shall be allocated to

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the electric utilities based on their respective
percentages of kilowatthours delivered to delivery
services customers to the aggregate kilowatthour
deliveries by the electric utilities to delivery services
customers for the year ended December 31, 2021. In order
to achieve these allocation percentages between or among
the electric utilities, the Agency shall require each
applicant that is selected in the procurement event to
enter into a contract with each electric utility for the
sale and purchase of renewable energy credits from each
new renewable energy facility to be constructed and
operated by the applicant, with the sale and purchase
obligations under the contracts to aggregate to the total
number of renewable energy credits per year to be supplied
by the applicant from the new renewable energy facility.
(7) The Agency shall submit its proposed selection of
applicants, new renewable energy facilities to be
constructed, and renewable energy credit amounts for each
procurement event to the Commission for approval. The
Commission shall, within 2 business days after receipt of
the Agency's proposed selections, approve the proposed
selections if it determines that the applicants and the
new renewable energy facilities to be constructed meet the
selection criteria set forth in this subsection (c-5) and
that the Agency seeks approval for contracts of applicable
durations aggregating to no more than the maximum amount

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of renewable energy credits per year authorized by this
subsection (c-5) for the procurement event, at a price of
$30 per renewable energy credit.
(8) The Agency, in conjunction with its procurement
administrator if one is retained, the electric utilities,
and potential applicants for contracts to produce and
supply renewable energy credits pursuant to this
subsection (c-5), shall develop a standard form contract
for the sale, delivery and purchase of renewable energy
credits pursuant to this subsection (c-5). Each contract
resulting from the first procurement event shall allow for
a commercial operation date for the new renewable energy
facility of either June 1, 2023 or June 1, 2024, with such
dates subject to adjustment as provided in this paragraph.
Each contract resulting from the second procurement event
shall provide for a commercial operation date on June 1
next occurring up to 48 months after execution of the
contract. Each contract shall provide that the owner shall
receive payments for renewable energy credits for the
applicable durations beginning with the commercial
operation date of the new renewable energy facility. The
form contract shall provide for adjustments to the
commercial operation and payment start dates as needed due
to any delays in completing the procurement and
contracting processes, in finalizing interconnection
agreements and installing interconnection facilities, and

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in obtaining other necessary governmental permits and
approvals. The form contract shall be, to the maximum
extent possible, consistent with standard electric
industry contracts for sale, delivery, and purchase of
renewable energy credits while taking into account the
specific requirements of this subsection (c-5). The form
contract shall provide for over-delivery and
under-delivery of renewable energy credits within
reasonable ranges during each 12-month period and penalty,
default, and enforcement provisions for failure of the
selling party to deliver renewable energy credits as
specified in the contract and to comply with the
requirements of this subsection (c-5). The standard form
contract shall specify that all renewable energy credits
delivered to the electric utility pursuant to the contract
shall be retired. The Agency shall make the proposed
contracts available for a reasonable period for comment by
potential applicants, and shall publish the final form
contract at least 30 days before the date of the first
procurement event.
(9) Coal to Solar and Energy Storage Initiative
Charge.
(A) By no later than July 1, 2022, each electric
utility that served more than 300,000 retail customers
in this State as of January 1, 2019 shall file a tariff
with the Commission for the billing and collection of

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a Coal to Solar and Energy Storage Initiative Charge
in accordance with subsection (i-5) of Section 16-108
of the Public Utilities Act, with such tariff to be
effective, following review and approval or
modification by the Commission, beginning January 1,
2023. The tariff shall provide for the calculation and
setting of the electric utility's Coal to Solar and
Energy Storage Initiative Charge to collect revenues
estimated to be sufficient, in the aggregate, (i) to
enable the electric utility to pay for the renewable
energy credits it has contracted to purchase in the
delivery year beginning June 1, 2023 and each delivery
year thereafter from new renewable energy facilities
located at the sites of qualifying electric generating
facilities, and (ii) to fund the grant payments to be
made in each delivery year by the Department of
Commerce and Economic Opportunity, or any successor
department or agency, which shall be referred to in
this subsection (c-5) as the Department, pursuant to
paragraph (10) of this subsection (c-5). The electric
utility's tariff shall provide for the billing and
collection of the Coal to Solar and Energy Storage
Initiative Charge on each kilowatthour of electricity
delivered to its delivery services customers within
its service territory and shall provide for an annual
reconciliation of revenues collected with actual

10400HB1700sam002 - 140 - LRB104 08228 AAS 38463 a
costs, in accordance with subsection (i-5) of Section
16-108 of the Public Utilities Act.
(B) Each electric utility shall remit on a monthly
basis to the State Treasurer, for deposit in the Coal
to Solar and Energy Storage Initiative Fund provided
for in this subsection (c-5), the electric utility's
collections of the Coal to Solar and Energy Storage
Initiative Charge in the amount estimated to be needed
by the Department for grant payments pursuant to grant
contracts entered into by the Department pursuant to
paragraph (10) of this subsection (c-5).
(10) Coal to Solar and Energy Storage Initiative Fund.
(A) The Coal to Solar and Energy Storage
Initiative Fund is established as a special fund in
the State treasury. The Coal to Solar and Energy
Storage Initiative Fund is authorized to receive, by
statutory deposit, that portion specified in item (B)
of paragraph (9) of this subsection (c-5) of moneys
collected by electric utilities through imposition of
the Coal to Solar and Energy Storage Initiative Charge
required by this subsection (c-5). The Coal to Solar
and Energy Storage Initiative Fund shall be
administered by the Department to provide grants to
support the installation and operation of energy
storage facilities at the sites of qualifying electric
generating facilities meeting the criteria specified

10400HB1700sam002 - 141 - LRB104 08228 AAS 38463 a
in this paragraph (10).
(B) The Coal to Solar and Energy Storage
Initiative Fund shall not be subject to sweeps,
administrative charges, or chargebacks, including, but
not limited to, those authorized under Section 8h of
the State Finance Act, that would in any way result in
the transfer of those funds from the Coal to Solar and
Energy Storage Initiative Fund to any other fund of
this State or in having any such funds utilized for any
purpose other than the express purposes set forth in
this paragraph (10).
(C) The Department shall utilize up to
$280,500,000 in the Coal to Solar and Energy Storage
Initiative Fund for grants, assuming sufficient
qualifying applicants, to support installation of
energy storage facilities at the sites of up to 3
qualifying electric generating facilities located in
the Midcontinent Independent System Operator, Inc.,
region in Illinois and the sites of up to 2 qualifying
electric generating facilities located in the PJM
Interconnection, LLC region in Illinois that meet the
criteria set forth in this subparagraph (C). The
criteria for receipt of a grant pursuant to this
subparagraph (C) are as follows:
(1) the electric generating facility at the
site has, or had prior to retirement, an electric

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generating capacity of at least 150 megawatts;
(2) the electric generating facility burns (or
burned prior to retirement) coal as its primary
source of fuel;
(3) if the electric generating facility is
retired, it was retired subsequent to January 1,
2016;
(4) the owner of the electric generating
facility has not been selected by the Agency
pursuant to this subsection (c-5) of this Section
to enter into a contract to sell renewable energy
credits to one or more electric utilities from a
new renewable energy facility located or to be
located at or adjacent to the site at which the
electric generating facility is located;
(5) the electric generating facility located
at the site was at one time owned, in whole or in
part, by a public utility as defined in Section
3-105 of the Public Utilities Act;
(6) the electric generating facility at the
site is not owned by (i) an electric cooperative
as defined in Section 3-119 of the Public
Utilities Act, or (ii) an entity described in
subsection (b)(1) of Section 3-105 of the Public
Utilities Act, or an association or consortium of
or an entity owned by entities described in items

10400HB1700sam002 - 143 - LRB104 08228 AAS 38463 a
(i) or (ii);
(7) the proposed energy storage facility at
the site will have energy storage capacity of at
least 37 megawatts;
(8) the owner commits to place the energy
storage facility into commercial operation on
either June 1, 2023, June 1, 2024, or June 1, 2025,
with such date subject to adjustment as needed due
to any delays in completing the grant contracting
process, in finalizing interconnection agreements
and in installing interconnection facilities, and
in obtaining necessary governmental permits and
approvals;
(9) the owner agrees that the new energy
storage facility will be constructed or installed
by a qualified entity or entities consistent with
the requirements of subsection (g) of Section
16-128A of the Public Utilities Act and any rules
adopted under that Section;
(10) the owner agrees that personnel operating
the energy storage facility will have the
requisite skills, knowledge, training, experience,
and competence, which may be demonstrated by
completion or current participation and ultimate
completion by employees of an accredited or
otherwise recognized apprenticeship program for

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the employee's particular craft, trade, or skill,
including through training and education courses
and opportunities offered by the owner to
employees of the coal-fueled electric generating
facility or by previous employment experience
performing the employee's particular work skill or
function;
(11) the owner commits that not less than the
prevailing wage, as determined pursuant to the
Prevailing Wage Act, will be paid to the owner's
employees engaged in construction activities
associated with the new energy storage facility
and to the employees of the owner's contractors
engaged in construction activities associated with
the new energy storage facility, and that, on or
before the commercial operation date of the new
energy storage facility, the owner shall file a
report with the Department certifying that the
requirements of this subparagraph (11) have been
met; and
(12) the owner commits that if selected to
receive a grant, it will negotiate a project labor
agreement for the construction of the new energy
storage facility that includes provisions
requiring the parties to the agreement to work
together to establish diversity threshold

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requirements and to ensure best efforts to meet
diversity targets, improve diversity at the
applicable job site, create diverse apprenticeship
opportunities, and create opportunities to employ
former coal-fired power plant workers.
The Department shall accept applications for this
grant program until March 31, 2022 and shall announce
the award of grants no later than June 1, 2022. The
Department shall make the grant payments to a
recipient in equal annual amounts for 10 years
following the date the energy storage facility is
placed into commercial operation. The annual grant
payments to a qualifying energy storage facility shall
be $110,000 per megawatt of energy storage capacity,
with total annual grant payments pursuant to this
subparagraph (C) for qualifying energy storage
facilities not to exceed $28,050,000 in any year.
(D) Grants of funding for energy storage
facilities pursuant to subparagraph (C) of this
paragraph (10), from the Coal to Solar and Energy
Storage Initiative Fund, shall be memorialized in
grant contracts between the Department and the
recipient. The grant contracts shall specify the date
or dates in each year on which the annual grant
payments shall be paid.
(E) All disbursements from the Coal to Solar and

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Energy Storage Initiative Fund shall be made only upon
warrants of the Comptroller drawn upon the Treasurer
as custodian of the Fund upon vouchers signed by the
Director of the Department or by the person or persons
designated by the Director of the Department for that
purpose. The Comptroller is authorized to draw the
warrants upon vouchers so signed. The Treasurer shall
accept all written warrants so signed and shall be
released from liability for all payments made on those
warrants.
(11) Diversity, equity, and inclusion plans.
(A) Each applicant selected in a procurement event
to contract to supply renewable energy credits in
accordance with this subsection (c-5) and each owner
selected by the Department to receive a grant or
grants to support the construction and operation of a
new energy storage facility or facilities in
accordance with this subsection (c-5) shall, within 60
days following the Commission's approval of the
applicant to contract to supply renewable energy
credits or within 60 days following execution of a
grant contract with the Department, as applicable,
submit to the Commission a diversity, equity, and
inclusion plan setting forth the applicant's or
owner's numeric goals for the diversity composition of
its supplier entities for the new renewable energy

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facility or new energy storage facility, as
applicable, which shall be referred to for purposes of
this paragraph (11) as the project, and the
applicant's or owner's action plan and schedule for
achieving those goals.
(B) For purposes of this paragraph (11), diversity
composition shall be based on the percentage, which
shall be a minimum of 25%, of eligible expenditures
for contract awards for materials and services (which
shall be defined in the plan) to business enterprises
owned by minority persons, women, or persons with
disabilities as defined in Section 2 of the Business
Enterprise for Minorities, Women, and Persons with
Disabilities Act, to LGBTQ business enterprises, to
veteran-owned business enterprises, and to business
enterprises located in environmental justice
communities. The diversity composition goals of the
plan may include eligible expenditures in areas for
vendor or supplier opportunities in addition to
development and construction of the project, and may
exclude from eligible expenditures materials and
services with limited market availability, limited
production and availability from suppliers in the
United States, such as solar panels and storage
batteries, and material and services that are subject
to critical energy infrastructure or cybersecurity

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requirements or restrictions. The plan may provide
that the diversity composition goals may be met
through Tier 1 Direct or Tier 2 subcontracting
expenditures or a combination thereof for the project.
(C) The plan shall provide for, but not be limited
to: (i) internal initiatives, including multi-tier
initiatives, by the applicant or owner, or by its
engineering, procurement and construction contractor
if one is used for the project, which for purposes of
this paragraph (11) shall be referred to as the EPC
contractor, to enable diverse businesses to be
considered fairly for selection to provide materials
and services; (ii) requirements for the applicant or
owner or its EPC contractor to proactively solicit and
utilize diverse businesses to provide materials and
services; and (iii) requirements for the applicant or
owner or its EPC contractor to hire a diverse
workforce for the project. The plan shall include a
description of the applicant's or owner's diversity
recruiting efforts both for the project and for other
areas of the applicant's or owner's business
operations. The plan shall provide for the imposition
of financial penalties on the applicant's or owner's
EPC contractor for failure to exercise best efforts to
comply with and execute the EPC contractor's diversity
obligations under the plan. The plan may provide for

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the applicant or owner to set aside a portion of the
work on the project to serve as an incubation program
for qualified businesses, as specified in the plan,
owned by minority persons, women, persons with
disabilities, LGBTQ persons, and veterans, and
businesses located in environmental justice
communities, seeking to enter the renewable energy
industry.
(D) The applicant or owner may submit a revised or
updated plan to the Commission from time to time as
circumstances warrant. The applicant or owner shall
file annual reports with the Commission detailing the
applicant's or owner's progress in implementing its
plan and achieving its goals and any modifications the
applicant or owner has made to its plan to better
achieve its diversity, equity and inclusion goals. The
applicant or owner shall file a final report on the
fifth June 1 following the commercial operation date
of the new renewable energy resource or new energy
storage facility, but the applicant or owner shall
thereafter continue to be subject to applicable
reporting requirements of Section 5-117 of the Public
Utilities Act.
(c-10) Equity accountability system. It is the purpose of
this subsection (c-10) to create an equity accountability
system, which includes the minimum equity standards for all

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renewable energy procurements, the equity category of the
Adjustable Block Program, and the equity prioritization for
noncompetitive procurements, that is successful in advancing
priority access to the clean energy economy for businesses and
workers from communities that have been excluded from economic
opportunities in the energy sector, have been subject to
disproportionate levels of pollution, and have
disproportionately experienced negative public health
outcomes. Further, it is the purpose of this subsection to
ensure that this equity accountability system is successful in
advancing equity across Illinois by providing access to the
clean energy economy for businesses and workers from
communities that have been historically excluded from economic
opportunities in the energy sector, have been subject to
disproportionate levels of pollution, and have
disproportionately experienced negative public health
outcomes.
(1) Minimum equity standards. The Agency shall create
programs with the purpose of increasing access to and
development of equity eligible contractors, who are prime
contractors and subcontractors, across all of the programs
it manages. All applications for renewable energy credit
procurements shall comply with specific minimum equity
commitments. Starting in the delivery year immediately
following the next long-term renewable resources
procurement plan, at least 10% of the project workforce

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for each entity participating in a procurement program
outlined in this subsection (c-10) must be done by equity
eligible persons or equity eligible contractors. The
Agency shall increase the minimum percentage each delivery
year thereafter by increments that ensure a statewide
average of 30% of the project workforce for each entity
participating in a procurement program is done by equity
eligible persons or equity eligible contractors by 2030.
The Agency shall propose a schedule of percentage
increases to the minimum equity standards in its draft
revised renewable energy resources procurement plan
submitted to the Commission for approval pursuant to
paragraph (5) of subsection (b) of Section 16-111.5 of the
Public Utilities Act. In determining these annual
increases, the Agency shall have the discretion to
establish different minimum equity standards for different
types of procurements and different regions of the State
if the Agency finds that doing so will further the
purposes of this subsection (c-10). The proposed schedule
of annual increases shall be revisited and updated on an
annual basis. Revisions shall be developed with
stakeholder input, including from equity eligible persons,
equity eligible contractors, clean energy industry
representatives, and community-based organizations that
work with such persons and contractors.
(A) At the start of each delivery year, the Agency

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shall require a compliance plan from each entity
participating in a procurement program of subsection
(c) of this Section that demonstrates how they will
achieve compliance with the minimum equity standard
percentage for work completed in that delivery year.
If an entity applies for its approved vendor or
designee status between delivery years, the Agency
shall require a compliance plan at the time of
application.
(B) Halfway through each delivery year, the Agency
shall require each entity participating in a
procurement program to confirm that it will achieve
compliance in that delivery year, when applicable. The
Agency may offer corrective action plans to entities
that are not on track to achieve compliance.
(C) At the end of each delivery year, each entity
participating and completing work in that delivery
year in a procurement program of subsection (c) shall
submit a report to the Agency that demonstrates how it
achieved compliance with the minimum equity standards
percentage for that delivery year.
(D) The Agency shall prohibit participation in
procurement programs by an approved vendor or
designee, as applicable, or entities with which an
approved vendor or designee, as applicable, shares a
common parent company if an approved vendor or

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designee, as applicable, failed to meet the minimum
equity standards for the prior delivery year. Waivers
approved for lack of equity eligible persons or equity
eligible contractors in a geographic area of a project
shall not count against the approved vendor or
designee. The Agency shall offer a corrective action
plan for any such entities to assist them in obtaining
compliance and shall allow continued access to
procurement programs upon an approved vendor or
designee demonstrating compliance.
(E) The Agency shall pursue efficiencies achieved
by combining with other approved vendor or designee
reporting.
(2) Equity accountability system within the Adjustable
Block program. The equity category described in item (vi)
of subparagraph (K) of subsection (c) is only available to
applicants that are equity eligible contractors.
(3) Equity accountability system within competitive
procurements. Through its long-term renewable resources
procurement plan, the Agency shall develop requirements
for ensuring that competitive procurement processes,
including utility-scale solar, utility-scale wind, and
brownfield site photovoltaic projects, advance the equity
goals of this subsection (c-10). Subject to Commission
approval, the Agency shall develop bid application
requirements and a bid evaluation methodology for ensuring

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that utilization of equity eligible contractors, whether
as bidders or as participants on project development, is
optimized, including requiring that winning or successful
applicants for utility-scale projects are or will partner
with equity eligible contractors and giving preference to
bids through which a higher portion of contract value
flows to equity eligible contractors. To the extent
practicable, entities participating in competitive
procurements shall also be required to meet all the equity
accountability requirements for approved vendors and their
designees under this subsection (c-10). In developing
these requirements, the Agency shall also consider whether
equity goals can be further advanced through additional
measures.
(4) In the first revision to the long-term renewable
energy resources procurement plan and each revision
thereafter, the Agency shall include the following:
(A) The current status and number of equity
eligible contractors listed in the Energy Workforce
Equity Database designed in subsection (c-25),
including the number of equity eligible contractors
with current certifications as issued by the Agency.
(B) A mechanism for measuring, tracking, and
reporting project workforce at the approved vendor or
designee level, as applicable, which shall include a
measurement methodology and records to be made

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available for audit by the Agency or the Program
Administrator.
(C) A program for approved vendors, designees,
eligible persons, and equity eligible contractors to
receive trainings, guidance, and other support from
the Agency or its designee regarding the equity
category outlined in item (vi) of subparagraph (K) of
paragraph (1) of subsection (c) and in meeting the
minimum equity standards of this subsection (c-10).
(D) A process for certifying equity eligible
contractors and equity eligible persons. The
certification process shall coordinate with the Energy
Workforce Equity Database set forth in subsection
(c-25).
(E) An application for waiver of the minimum
equity standards of this subsection, which the Agency
shall have the discretion to grant in rare
circumstances. The Agency may grant such a waiver
where the applicant provides evidence of significant
efforts toward meeting the minimum equity commitment,
including: use of the Energy Workforce Equity
Database; efforts to hire or contract with entities
that hire eligible persons; and efforts to establish
contracting relationships with eligible contractors.
The Agency shall support applicants in understanding
the Energy Workforce Equity Database and other

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resources for pursuing compliance of the minimum
equity standards. Waivers shall be project-specific,
unless the Agency deems it necessary to grant a waiver
across a portfolio of projects, and in effect for no
longer than one year. Any waiver extension or
subsequent waiver request from an applicant shall be
subject to the requirements of this Section and shall
specify efforts made to reach compliance. When
considering whether to grant a waiver, and to what
extent, the Agency shall consider the degree to which
similarly situated applicants have been able to meet
these minimum equity commitments. For repeated waiver
requests for specific lack of eligible persons or
eligible contractors available, the Agency shall make
recommendations to target recruitment to add such
eligible persons or eligible contractors to the
database.
(5) The Agency shall collect information about work on
projects or portfolios of projects subject to these
minimum equity standards to ensure compliance with this
subsection (c-10). Reporting in furtherance of this
requirement may be combined with other annual reporting
requirements. Such reporting shall include proof of
certification of each equity eligible contractor or equity
eligible person during the applicable time period.
(6) The Agency shall keep confidential all information

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and communication that provides private or personal
information.
(7) Modifications to the equity accountability system.
As part of the update of the long-term renewable resources
procurement plan to be initiated in 2023, or sooner if the
Agency deems necessary, the Agency shall determine the
extent to which the equity accountability system described
in this subsection (c-10) has advanced the goals of this
amendatory Act of the 102nd General Assembly, including
through the inclusion of equity eligible persons and
equity eligible contractors in renewable energy credit
projects. If the Agency finds that the equity
accountability system has failed to meet those goals to
its fullest potential, the Agency may revise the following
criteria for future Agency procurements: (A) the
percentage of project workforce, or other appropriate
workforce measure, certified as equity eligible persons or
equity eligible contractors; (B) definitions for equity
investment eligible persons and equity investment eligible
community; and (C) such other modifications necessary to
advance the goals of this amendatory Act of the 102nd
General Assembly effectively. Such revised criteria may
also establish distinct equity accountability systems for
different types of procurements or different regions of
the State if the Agency finds that doing so will further
the purposes of such programs. Revisions shall be

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developed with stakeholder input, including from equity
eligible persons, equity eligible contractors, and
community-based organizations that work with such persons
and contractors.
(c-15) Racial discrimination elimination powers and
process.
(1) Purpose. It is the purpose of this subsection to
empower the Agency and other State actors to remedy racial
discrimination in Illinois' clean energy economy as
effectively and expediently as possible, including through
the use of race-conscious remedies, such as race-conscious
contracting and hiring goals, as consistent with State and
federal law.
(2) Racial disparity and discrimination review
process.
(A) Within one year after awarding contracts using
the equity actions processes established in this
Section, the Agency shall publish a report evaluating
the effectiveness of the equity actions point criteria
of this Section in increasing participation of equity
eligible persons and equity eligible contractors. The
report shall disaggregate participating workers and
contractors by race and ethnicity. The report shall be
forwarded to the Governor, the General Assembly, and
the Illinois Commerce Commission and be made available
to the public.

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(B) As soon as is practicable thereafter, the
Agency, in consultation with the Department of
Commerce and Economic Opportunity, Department of
Labor, and other agencies that may be relevant, shall
commission and publish a disparity and availability
study that measures the presence and impact of
discrimination on minority businesses and workers in
Illinois' clean energy economy. The Agency may hire
consultants and experts to conduct the disparity and
availability study, with the retention of those
consultants and experts exempt from the requirements
of Section 20-10 of the Illinois Procurement Code. The
Illinois Power Agency shall forward a copy of its
findings and recommendations to the Governor, the
General Assembly, and the Illinois Commerce
Commission. If the disparity and availability study
establishes a strong basis in evidence that there is
discrimination in Illinois' clean energy economy, the
Agency, Department of Commerce and Economic
Opportunity, Department of Labor, Department of
Corrections, and other appropriate agencies shall take
appropriate remedial actions, including race-conscious
remedial actions as consistent with State and federal
law, to effectively remedy this discrimination. Such
remedies may include modification of the equity
accountability system as described in subsection

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(c-10).
(c-20) Program data collection.
(1) Purpose. Data collection, data analysis, and
reporting are critical to ensure that the benefits of the
clean energy economy provided to Illinois residents and
businesses are equitably distributed across the State. The
Agency shall collect data from program applicants in order
to track and improve equitable distribution of benefits
across Illinois communities for all procurements the
Agency conducts. The Agency shall use this data to, among
other things, measure any potential impact of racial
discrimination on the distribution of benefits and provide
information necessary to correct any discrimination
through methods consistent with State and federal law.
(2) Agency collection of program data. The Agency
shall collect demographic and geographic data for each
entity awarded contracts under any Agency-administered
program.
(3) Required information to be collected. The Agency
shall collect the following information from applicants
and program participants where applicable:
(A) demographic information, including racial or
ethnic identity for real persons employed, contracted,
or subcontracted through the program and owners of
businesses or entities that apply to receive renewable
energy credits from the Agency;

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(B) geographic location of the residency of real
persons employed, contracted, or subcontracted through
the program and geographic location of the
headquarters of the business or entity that applies to
receive renewable energy credits from the Agency; and
(C) any other information the Agency determines is
necessary for the purpose of achieving the purpose of
this subsection.
(4) Publication of collected information. The Agency
shall publish, at least annually, information on the
demographics of program participants on an aggregate
basis.
(5) Nothing in this subsection shall be interpreted to
limit the authority of the Agency, or other agency or
department of the State, to require or collect demographic
information from applicants of other State programs.
(c-25) Energy Workforce Equity Database.
(1) The Agency, in consultation with the Department of
Commerce and Economic Opportunity, shall create an Energy
Workforce Equity Database, and may contract with a third
party to do so ("database program administrator"). If the
Department decides to contract with a third party, that
third party shall be exempt from the requirements of
Section 20-10 of the Illinois Procurement Code. The Energy
Workforce Equity Database shall be a searchable database
of suppliers, vendors, and subcontractors for clean energy

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industries that is:
(A) publicly accessible;
(B) easy for people to find and use;
(C) organized by company specialty or field;
(D) region-specific; and
(E) populated with information including, but not
limited to, contacts for suppliers, vendors, or
subcontractors who are minority and women-owned
business enterprise certified or who participate or
have participated in any of the programs described in
this Act.
(2) The Agency shall create an easily accessible,
public facing online tool using the database information
that includes, at a minimum, the following:
(A) a map of environmental justice and equity
investment eligible communities;
(B) job postings and recruiting opportunities;
(C) a means by which recruiting clean energy
companies can find and interact with current or former
participants of clean energy workforce training
programs;
(D) information on workforce training service
providers and training opportunities available to
prospective workers;
(E) renewable energy company diversity reporting;
(F) a list of equity eligible contractors with

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their contact information, types of work performed,
and locations worked in;
(G) reporting on outcomes of the programs
described in the workforce programs of the Energy
Transition Act, including information such as, but not
limited to, retention rate, graduation rate, and
placement rates of trainees; and
(H) information about the Jobs and Environmental
Justice Grant Program, the Clean Energy Jobs and
Justice Fund, and other sources of capital.
(3) The Agency shall ensure the database is regularly
updated to ensure information is current and shall
coordinate with the Department of Commerce and Economic
Opportunity to ensure that it includes information on
individuals and entities that are or have participated in
the Clean Jobs Workforce Network Program, Clean Energy
Contractor Incubator Program, Returning Residents Clean
Jobs Training Program, or Clean Energy Primes Contractor
Accelerator Program.
(c-30) Enforcement of minimum equity standards. All
entities seeking renewable energy credits must submit an
annual report to demonstrate compliance with each of the
equity commitments required under subsection (c-10). If the
Agency concludes the entity has not met or maintained its
minimum equity standards required under the applicable
subparagraphs under subsection (c-10), the Agency shall deny

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the entity's ability to participate in procurement programs in
subsection (c), including by withholding approved vendor or
designee status. The Agency may require the entity to enter
into a corrective action plan. An entity that is not
recertified for failing to meet required equity actions in
subparagraph (c-10) may reapply once they have a corrective
action plan and achieve compliance with the minimum equity
standards.
(d) Clean coal portfolio standard.
(1) The procurement plans shall include electricity
generated using clean coal. Each utility shall enter into
one or more sourcing agreements with the initial clean
coal facility, as provided in paragraph (3) of this
subsection (d), covering electricity generated by the
initial clean coal facility representing at least 5% of
each utility's total supply to serve the load of eligible
retail customers in 2015 and each year thereafter, as
described in paragraph (3) of this subsection (d), subject
to the limits specified in paragraph (2) of this
subsection (d). It is the goal of the State that by January
1, 2025, 25% of the electricity used in the State shall be
generated by cost-effective clean coal facilities. For
purposes of this subsection (d), "cost-effective" means
that the expenditures pursuant to such sourcing agreements
do not cause the limit stated in paragraph (2) of this
subsection (d) to be exceeded and do not exceed cost-based

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benchmarks, which shall be developed to assess all
expenditures pursuant to such sourcing agreements covering
electricity generated by clean coal facilities, other than
the initial clean coal facility, by the procurement
administrator, in consultation with the Commission staff,
Agency staff, and the procurement monitor and shall be
subject to Commission review and approval.
A utility party to a sourcing agreement shall
immediately retire any emission credits that it receives
in connection with the electricity covered by such
agreement.
Utilities shall maintain adequate records documenting
the purchases under the sourcing agreement to comply with
this subsection (d) and shall file an accounting with the
load forecast that must be filed with the Agency by July 15
of each year, in accordance with subsection (d) of Section
16-111.5 of the Public Utilities Act.
A utility shall be deemed to have complied with the
clean coal portfolio standard specified in this subsection
(d) if the utility enters into a sourcing agreement as
required by this subsection (d).
(2) For purposes of this subsection (d), the required
execution of sourcing agreements with the initial clean
coal facility for a particular year shall be measured as a
percentage of the actual amount of electricity
(megawatt-hours) supplied by the electric utility to

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

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the amount paid per kilowatthour by those customers
during the year ending May 31, 2011 or 1.5% of the
amount paid per kilowatthour by those customers during
the year ending May 31, 2009;
(D) in 2013, the greater of an additional 0.5% of
the amount paid per kilowatthour by those customers
during the year ending May 31, 2012 or 2% of the amount
paid per kilowatthour by those customers during the
year ending May 31, 2009; and
(E) thereafter, the total amount paid under
sourcing agreements with clean coal facilities
pursuant to the procurement plan for any single year
shall be reduced by an amount necessary to limit the
estimated average net increase due to the cost of
these resources included in the amounts paid by
eligible retail customers in connection with electric
service to no more than the greater of (i) 2.015% of
the amount paid per kilowatthour by those customers
during the year ending May 31, 2009 or (ii) the
incremental amount per kilowatthour paid for these
resources in 2013. These requirements may be altered
only as provided by statute.
No later than June 30, 2015, the Commission shall
review the limitation on the total amount paid under
sourcing agreements, if any, with clean coal facilities
pursuant to this subsection (d) and report to the General

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Assembly its findings as to whether that limitation unduly
constrains the amount of electricity generated by
cost-effective clean coal facilities that is covered by
sourcing agreements.
(3) Initial clean coal facility. In order to promote
development of clean coal facilities in Illinois, each
electric utility subject to this Section shall execute a
sourcing agreement to source electricity from a proposed
clean coal facility in Illinois (the "initial clean coal
facility") that will have a nameplate capacity of at least
500 MW when commercial operation commences, that has a
final Clean Air Act permit on June 1, 2009 (the effective
date of Public Act 95-1027), and that will meet the
definition of clean coal facility in Section 1-10 of this
Act when commercial operation commences. The sourcing
agreements with this initial clean coal facility shall be
subject to both approval of the initial clean coal
facility by the General Assembly and satisfaction of the
requirements of paragraph (4) of this subsection (d) and
shall be executed within 90 days after any such approval
by the General Assembly. The Agency and the Commission
shall have authority to inspect all books and records
associated with the initial clean coal facility during the
term of such a sourcing agreement. A utility's sourcing
agreement for electricity produced by the initial clean
coal facility shall include:

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(A) a formula contractual price (the "contract
price") approved pursuant to paragraph (4) of this
subsection (d), which shall:
(i) be determined using a cost of service
methodology employing either a level or deferred
capital recovery component, based on a capital
structure consisting of 45% equity and 55% debt,
and a return on equity as may be approved by the
Federal Energy Regulatory Commission, which in any
case may not exceed the lower of 11.5% or the rate
of return approved by the General Assembly
pursuant to paragraph (4) of this subsection (d);
and
(ii) provide that all miscellaneous net
revenue, including but not limited to net revenue
from the sale of emission allowances, if any,
substitute natural gas, if any, grants or other
support provided by the State of Illinois or the
United States Government, firm transmission
rights, if any, by-products produced by the
facility, energy or capacity derived from the
facility and not covered by a sourcing agreement
pursuant to paragraph (3) of this subsection (d)
or item (5) of subsection (d) of Section 16-115 of
the Public Utilities Act, whether generated from
the synthesis gas derived from coal, from SNG, or

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from natural gas, shall be credited against the
revenue requirement for this initial clean coal
facility;
(B) power purchase provisions, which shall:
(i) provide that the utility party to such
sourcing agreement shall pay the contract price
for electricity delivered under such sourcing
agreement;
(ii) require delivery of electricity to the
regional transmission organization market of the
utility that is party to such sourcing agreement;
(iii) require the utility party to such
sourcing agreement to buy from the initial clean
coal facility in each hour an amount of energy
equal to all clean coal energy made available from
the initial clean coal facility during such hour
times a fraction, the numerator of which is such
utility's retail market sales of electricity
(expressed in kilowatthours sold) in the State
during the prior calendar month and the
denominator of which is the total retail market
sales of electricity (expressed in kilowatthours
sold) in the State by utilities during such prior
month and the sales of electricity (expressed in
kilowatthours sold) in the State by alternative
retail electric suppliers during such prior month

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

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retail electric suppliers during such prior month
that are subject to the requirements of this
subsection (d) and paragraph (5) of subsection (d)
of Section 16-115 of the Public Utilities Act,
provided that the amount paid by the utility in
any year will be limited by paragraph (2) of this
subsection (d);
(ii) provide that the utility's payment
obligation in respect of the quantity of
electricity determined pursuant to the preceding
clause (i) shall be limited to an amount equal to
(1) the difference between the contract price
determined pursuant to subparagraph (A) of
paragraph (3) of this subsection (d) and the
day-ahead price for electricity delivered to the
regional transmission organization market of the
utility that is party to such sourcing agreement
(or any successor delivery point at which such
utility's supply obligations are financially
settled on an hourly basis) (the "reference
price") on the day preceding the day on which the
electricity is delivered to the initial clean coal
facility busbar, multiplied by (2) the quantity of
electricity determined pursuant to the preceding
clause (i); and
(iii) not require the utility to take physical

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delivery of the electricity produced by the
facility;
(D) general provisions, which shall:
(i) specify a term of no more than 30 years,
commencing on the commercial operation date of the
facility;
(ii) provide that utilities shall maintain
adequate records documenting purchases under the
sourcing agreements entered into to comply with
this subsection (d) and shall file an accounting
with the load forecast that must be filed with the
Agency by July 15 of each year, in accordance with
subsection (d) of Section 16-111.5 of the Public
Utilities Act;
(iii) provide that all costs associated with
the initial clean coal facility will be
periodically reported to the Federal Energy
Regulatory Commission and to purchasers in
accordance with applicable laws governing
cost-based wholesale power contracts;
(iv) permit the Illinois Power Agency to
assume ownership of the initial clean coal
facility, without monetary consideration and
otherwise on reasonable terms acceptable to the
Agency, if the Agency so requests no less than 3
years prior to the end of the stated contract

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term;
(v) require the owner of the initial clean
coal facility to provide documentation to the
Commission each year, starting in the facility's
first year of commercial operation, accurately
reporting the quantity of carbon emissions from
the facility that have been captured and
sequestered and report any quantities of carbon
released from the site or sites at which carbon
emissions were sequestered in prior years, based
on continuous monitoring of such sites. If, in any
year after the first year of commercial operation,
the owner of the facility fails to demonstrate
that the initial clean coal facility captured and
sequestered at least 50% of the total carbon
emissions that the facility would otherwise emit
or that sequestration of emissions from prior
years has failed, resulting in the release of
carbon dioxide into the atmosphere, the owner of
the facility must offset excess emissions. Any
such carbon offsets must be permanent, additional,
verifiable, real, located within the State of
Illinois, and legally and practicably enforceable.
The cost of such offsets for the facility that are
not recoverable shall not exceed $15 million in
any given year. No costs of any such purchases of

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carbon offsets may be recovered from a utility or
its customers. All carbon offsets purchased for
this purpose and any carbon emission credits
associated with sequestration of carbon from the
facility must be permanently retired. The initial
clean coal facility shall not forfeit its
designation as a clean coal facility if the
facility fails to fully comply with the applicable
carbon sequestration requirements in any given
year, provided the requisite offsets are
purchased. However, the Attorney General, on
behalf of the People of the State of Illinois, may
specifically enforce the facility's sequestration
requirement and the other terms of this contract
provision. Compliance with the sequestration
requirements and offset purchase requirements
specified in paragraph (3) of this subsection (d)
shall be reviewed annually by an independent
expert retained by the owner of the initial clean
coal facility, with the advance written approval
of the Attorney General. The Commission may, in
the course of the review specified in item (vii),
reduce the allowable return on equity for the
facility if the facility willfully fails to comply
with the carbon capture and sequestration
requirements set forth in this item (v);

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(vi) include limits on, and accordingly
provide for modification of, the amount the
utility is required to source under the sourcing
agreement consistent with paragraph (2) of this
subsection (d);
(vii) require Commission review: (1) to
determine the justness, reasonableness, and
prudence of the inputs to the formula referenced
in subparagraphs (A)(i) through (A)(iii) of
paragraph (3) of this subsection (d), prior to an
adjustment in those inputs including, without
limitation, the capital structure and return on
equity, fuel costs, and other operations and
maintenance costs and (2) to approve the costs to
be passed through to customers under the sourcing
agreement by which the utility satisfies its
statutory obligations. Commission review shall
occur no less than every 3 years, regardless of
whether any adjustments have been proposed, and
shall be completed within 9 months;
(viii) limit the utility's obligation to such
amount as the utility is allowed to recover
through tariffs filed with the Commission,
provided that neither the clean coal facility nor
the utility waives any right to assert federal
pre-emption or any other argument in response to a

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purported disallowance of recovery costs;
(ix) limit the utility's or alternative retail
electric supplier's obligation to incur any
liability until such time as the facility is in
commercial operation and generating power and
energy and such power and energy is being
delivered to the facility busbar;
(x) provide that the owner or owners of the
initial clean coal facility, which is the
counterparty to such sourcing agreement, shall
have the right from time to time to elect whether
the obligations of the utility party thereto shall
be governed by the power purchase provisions or
the contract for differences provisions;
(xi) append documentation showing that the
formula rate and contract, insofar as they relate
to the power purchase provisions, have been
approved by the Federal Energy Regulatory
Commission pursuant to Section 205 of the Federal
Power Act;
(xii) provide that any changes to the terms of
the contract, insofar as such changes relate to
the power purchase provisions, are subject to
review under the public interest standard applied
by the Federal Energy Regulatory Commission
pursuant to Sections 205 and 206 of the Federal

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Power Act; and
(xiii) conform with customary lender
requirements in power purchase agreements used as
the basis for financing non-utility generators.
(4) Effective date of sourcing agreements with the
initial clean coal facility. Any proposed sourcing
agreement with the initial clean coal facility shall not
become effective unless the following reports are prepared
and submitted and authorizations and approvals obtained:
(i) Facility cost report. The owner of the initial
clean coal facility shall submit to the Commission,
the Agency, and the General Assembly a front-end
engineering and design study, a facility cost report,
method of financing (including but not limited to
structure and associated costs), and an operating and
maintenance cost quote for the facility (collectively
"facility cost report"), which shall be prepared in
accordance with the requirements of this paragraph (4)
of subsection (d) of this Section, and shall provide
the Commission and the Agency access to the work
papers, relied upon documents, and any other backup
documentation related to the facility cost report.
(ii) Commission report. Within 6 months following
receipt of the facility cost report, the Commission,
in consultation with the Agency, shall submit a report
to the General Assembly setting forth its analysis of

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the facility cost report. Such report shall include,
but not be limited to, a comparison of the costs
associated with electricity generated by the initial
clean coal facility to the costs associated with
electricity generated by other types of generation
facilities, an analysis of the rate impacts on
residential and small business customers over the life
of the sourcing agreements, and an analysis of the
likelihood that the initial clean coal facility will
commence commercial operation by and be delivering
power to the facility's busbar by 2016. To assist in
the preparation of its report, the Commission, in
consultation with the Agency, may hire one or more
experts or consultants, the costs of which shall be
paid for by the owner of the initial clean coal
facility. The Commission and Agency may begin the
process of selecting such experts or consultants prior
to receipt of the facility cost report.
(iii) General Assembly approval. The proposed
sourcing agreements shall not take effect unless,
based on the facility cost report and the Commission's
report, the General Assembly enacts authorizing
legislation approving (A) the projected price, stated
in cents per kilowatthour, to be charged for
electricity generated by the initial clean coal
facility, (B) the projected impact on residential and

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small business customers' bills over the life of the
sourcing agreements, and (C) the maximum allowable
return on equity for the project; and
(iv) Commission review. If the General Assembly
enacts authorizing legislation pursuant to
subparagraph (iii) approving a sourcing agreement, the
Commission shall, within 90 days of such enactment,
complete a review of such sourcing agreement. During
such time period, the Commission shall implement any
directive of the General Assembly, resolve any
disputes between the parties to the sourcing agreement
concerning the terms of such agreement, approve the
form of such agreement, and issue an order finding
that the sourcing agreement is prudent and reasonable.
The facility cost report shall be prepared as follows:
(A) The facility cost report shall be prepared by
duly licensed engineering and construction firms
detailing the estimated capital costs payable to one
or more contractors or suppliers for the engineering,
procurement and construction of the components
comprising the initial clean coal facility and the
estimated costs of operation and maintenance of the
facility. The facility cost report shall include:
(i) an estimate of the capital cost of the
core plant based on one or more front end
engineering and design studies for the

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gasification island and related facilities. The
core plant shall include all civil, structural,
mechanical, electrical, control, and safety
systems.
(ii) an estimate of the capital cost of the
balance of the plant, including any capital costs
associated with sequestration of carbon dioxide
emissions and all interconnects and interfaces
required to operate the facility, such as
transmission of electricity, construction or
backfeed power supply, pipelines to transport
substitute natural gas or carbon dioxide, potable
water supply, natural gas supply, water supply,
water discharge, landfill, access roads, and coal
delivery.
The quoted construction costs shall be expressed
in nominal dollars as of the date that the quote is
prepared and shall include capitalized financing costs
during construction, taxes, insurance, and other
owner's costs, and an assumed escalation in materials
and labor beyond the date as of which the construction
cost quote is expressed.
(B) The front end engineering and design study for
the gasification island and the cost study for the
balance of plant shall include sufficient design work
to permit quantification of major categories of

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materials, commodities and labor hours, and receipt of
quotes from vendors of major equipment required to
construct and operate the clean coal facility.
(C) The facility cost report shall also include an
operating and maintenance cost quote that will provide
the estimated cost of delivered fuel, personnel,
maintenance contracts, chemicals, catalysts,
consumables, spares, and other fixed and variable
operations and maintenance costs. The delivered fuel
cost estimate will be provided by a recognized third
party expert or experts in the fuel and transportation
industries. The balance of the operating and
maintenance cost quote, excluding delivered fuel
costs, will be developed based on the inputs provided
by duly licensed engineering and construction firms
performing the construction cost quote, potential
vendors under long-term service agreements and plant
operating agreements, or recognized third party plant
operator or operators.
The operating and maintenance cost quote
(including the cost of the front end engineering and
design study) shall be expressed in nominal dollars as
of the date that the quote is prepared and shall
include taxes, insurance, and other owner's costs, and
an assumed escalation in materials and labor beyond
the date as of which the operating and maintenance

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cost quote is expressed.
(D) The facility cost report shall also include an
analysis of the initial clean coal facility's ability
to deliver power and energy into the applicable
regional transmission organization markets and an
analysis of the expected capacity factor for the
initial clean coal facility.
(E) Amounts paid to third parties unrelated to the
owner or owners of the initial clean coal facility to
prepare the core plant construction cost quote,
including the front end engineering and design study,
and the operating and maintenance cost quote will be
reimbursed through Coal Development Bonds.
(5) Re-powering and retrofitting coal-fired power
plants previously owned by Illinois utilities to qualify
as clean coal facilities. During the 2009 procurement
planning process and thereafter, the Agency and the
Commission shall consider sourcing agreements covering
electricity generated by power plants that were previously
owned by Illinois utilities and that have been or will be
converted into clean coal facilities, as defined by
Section 1-10 of this Act. Pursuant to such procurement
planning process, the owners of such facilities may
propose to the Agency sourcing agreements with utilities
and alternative retail electric suppliers required to
comply with subsection (d) of this Section and item (5) of

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subsection (d) of Section 16-115 of the Public Utilities
Act, covering electricity generated by such facilities. In
the case of sourcing agreements that are power purchase
agreements, the contract price for electricity sales shall
be established on a cost of service basis. In the case of
sourcing agreements that are contracts for differences,
the contract price from which the reference price is
subtracted shall be established on a cost of service
basis. The Agency and the Commission may approve any such
utility sourcing agreements that do not exceed cost-based
benchmarks developed by the procurement administrator, in
consultation with the Commission staff, Agency staff and
the procurement monitor, subject to Commission review and
approval. The Commission shall have authority to inspect
all books and records associated with these clean coal
facilities during the term of any such contract.
(6) Costs incurred under this subsection (d) or
pursuant to a contract entered into under this subsection
(d) shall be deemed prudently incurred and reasonable in
amount and the electric utility shall be entitled to full
cost recovery pursuant to the tariffs filed with the
Commission.
(d-5) Zero emission standard.
(1) Beginning with the delivery year commencing on
June 1, 2017, the Agency shall, for electric utilities
that serve at least 100,000 retail customers in this

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State, procure contracts with zero emission facilities
that are reasonably capable of generating cost-effective
zero emission credits in an amount approximately equal to
16% of the actual amount of electricity delivered by each
electric utility to retail customers in the State during
calendar year 2014. For an electric utility serving fewer
than 100,000 retail customers in this State that
requested, under Section 16-111.5 of the Public Utilities
Act, that the Agency procure power and energy for all or a
portion of the utility's Illinois load for the delivery
year commencing June 1, 2016, the Agency shall procure
contracts with zero emission facilities that are
reasonably capable of generating cost-effective zero
emission credits in an amount approximately equal to 16%
of the portion of power and energy to be procured by the
Agency for the utility. The duration of the contracts
procured under this subsection (d-5) shall be for a term
of 10 years ending May 31, 2027. The quantity of zero
emission credits to be procured under the contracts shall
be all of the zero emission credits generated by the zero
emission facility in each delivery year; however, if the
zero emission facility is owned by more than one entity,
then the quantity of zero emission credits to be procured
under the contracts shall be the amount of zero emission
credits that are generated from the portion of the zero
emission facility that is owned by the winning supplier.

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The 16% value identified in this paragraph (1) is the
average of the percentage targets in subparagraph (B) of
paragraph (1) of subsection (c) of this Section for the 5
delivery years beginning June 1, 2017.
The procurement process shall be subject to the
following provisions:
(A) Those zero emission facilities that intend to
participate in the procurement shall submit to the
Agency the following eligibility information for each
zero emission facility on or before the date
established by the Agency:
(i) the in-service date and remaining useful
life of the zero emission facility;
(ii) the amount of power generated annually
for each of the years 2005 through 2015, and the
projected zero emission credits to be generated
over the remaining useful life of the zero
emission facility, which shall be used to
determine the capability of each facility;
(iii) the annual zero emission facility cost
projections, expressed on a per megawatthour
basis, over the next 6 delivery years, which shall
include the following: operation and maintenance
expenses; fully allocated overhead costs, which
shall be allocated using the methodology developed
by the Institute for Nuclear Power Operations;

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fuel expenditures; non-fuel capital expenditures;
spent fuel expenditures; a return on working
capital; the cost of operational and market risks
that could be avoided by ceasing operation; and
any other costs necessary for continued
operations, provided that "necessary" means, for
purposes of this item (iii), that the costs could
reasonably be avoided only by ceasing operations
of the zero emission facility; and
(iv) a commitment to continue operating, for
the duration of the contract or contracts executed
under the procurement held under this subsection
(d-5), the zero emission facility that produces
the zero emission credits to be procured in the
procurement.
The information described in item (iii) of this
subparagraph (A) may be submitted on a confidential
basis and shall be treated and maintained by the
Agency, the procurement administrator, and the
Commission as confidential and proprietary and exempt
from disclosure under subparagraphs (a) and (g) of
paragraph (1) of Section 7 of the Freedom of
Information Act. The Office of Attorney General shall
have access to, and maintain the confidentiality of,
such information pursuant to Section 6.5 of the
Attorney General Act.

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(B) The price for each zero emission credit
procured under this subsection (d-5) for each delivery
year shall be in an amount that equals the Social Cost
of Carbon, expressed on a price per megawatthour
basis. However, to ensure that the procurement remains
affordable to retail customers in this State if
electricity prices increase, the price in an
applicable delivery year shall be reduced below the
Social Cost of Carbon by the amount ("Price
Adjustment") by which the market price index for the
applicable delivery year exceeds the baseline market
price index for the consecutive 12-month period ending
May 31, 2016. If the Price Adjustment is greater than
or equal to the Social Cost of Carbon in an applicable
delivery year, then no payments shall be due in that
delivery year. The components of this calculation are
defined as follows:
(i) Social Cost of Carbon: The Social Cost of
Carbon is $16.50 per megawatthour, which is based
on the U.S. Interagency Working Group on Social
Cost of Carbon's price in the August 2016
Technical Update using a 3% discount rate,
adjusted for inflation for each year of the
program. Beginning with the delivery year
commencing June 1, 2023, the price per
megawatthour shall increase by $1 per

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megawatthour, and continue to increase by an
additional $1 per megawatthour each delivery year
thereafter.
(ii) Baseline market price index: The baseline
market price index for the consecutive 12-month
period ending May 31, 2016 is $31.40 per
megawatthour, which is based on the sum of (aa)
the average day-ahead energy price across all
hours of such 12-month period at the PJM
Interconnection LLC Northern Illinois Hub, (bb)
50% multiplied by the Base Residual Auction, or
its successor, capacity price for the rest of the
RTO zone group determined by PJM Interconnection
LLC, divided by 24 hours per day, and (cc) 50%
multiplied by the Planning Resource Auction, or
its successor, capacity price for Zone 4
determined by the Midcontinent Independent System
Operator, Inc., divided by 24 hours per day.
(iii) Market price index: The market price
index for a delivery year shall be the sum of
projected energy prices and projected capacity
prices determined as follows:
(aa) Projected energy prices: the
projected energy prices for the applicable
delivery year shall be calculated once for the
year using the forward market price for the

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

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divided by 24 hours per day, and where
such price is determined by the
Midcontinent Independent System Operator,
Inc.
(II) For the delivery year commencing
June 1, 2020, and each year thereafter,
the projected capacity price shall be
equal to the sum of (1) 50% multiplied by
the Base Residual Auction, or its
successor, price for the ComEd zone as
determined by PJM Interconnection LLC,
divided by 24 hours per day, and (2) 50%
multiplied by the resource auction price
determined in the resource auction
administered by the Midcontinent
Independent System Operator, Inc., in
which the largest percentage of load
cleared for Local Resource Zone 4, divided
by 24 hours per day, and where such price
is determined by the Midcontinent
Independent System Operator, Inc.
For purposes of this subsection (d-5):
"Rest of the RTO" and "ComEd Zone" shall have
the meaning ascribed to them by PJM
Interconnection, LLC.
"RTO" means regional transmission

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organization.
(C) No later than 45 days after June 1, 2017 (the
effective date of Public Act 99-906), the Agency shall
publish its proposed zero emission standard
procurement plan. The plan shall be consistent with
the provisions of this paragraph (1) and shall provide
that winning bids shall be selected based on public
interest criteria that include, but are not limited
to, minimizing carbon dioxide emissions that result
from electricity consumed in Illinois and minimizing
sulfur dioxide, nitrogen oxide, and particulate matter
emissions that adversely affect the citizens of this
State. In particular, the selection of winning bids
shall take into account the incremental environmental
benefits resulting from the procurement, such as any
existing environmental benefits that are preserved by
the procurements held under Public Act 99-906 and
would cease to exist if the procurements were not
held, including the preservation of zero emission
facilities. The plan shall also describe in detail how
each public interest factor shall be considered and
weighted in the bid selection process to ensure that
the public interest criteria are applied to the
procurement and given full effect.
For purposes of developing the plan, the Agency
shall consider any reports issued by a State agency,

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board, or commission under House Resolution 1146 of
the 98th General Assembly and paragraph (4) of
subsection (d) of this Section, as well as publicly
available analyses and studies performed by or for
regional transmission organizations that serve the
State and their independent market monitors.
Upon publishing of the zero emission standard
procurement plan, copies of the plan shall be posted
and made publicly available on the Agency's website.
All interested parties shall have 10 days following
the date of posting to provide comment to the Agency on
the plan. All comments shall be posted to the Agency's
website. Following the end of the comment period, but
no more than 60 days later than June 1, 2017 (the
effective date of Public Act 99-906), the Agency shall
revise the plan as necessary based on the comments
received and file its zero emission standard
procurement plan with the Commission.
If the Commission determines that the plan will
result in the procurement of cost-effective zero
emission credits, then the Commission shall, after
notice and hearing, but no later than 45 days after the
Agency filed the plan, approve the plan or approve
with modification. For purposes of this subsection
(d-5), "cost effective" means the projected costs of
procuring zero emission credits from zero emission

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facilities do not cause the limit stated in paragraph
(2) of this subsection to be exceeded.
(C-5) As part of the Commission's review and
acceptance or rejection of the procurement results,
the Commission shall, in its public notice of
successful bidders:
(i) identify how the winning bids satisfy the
public interest criteria described in subparagraph
(C) of this paragraph (1) of minimizing carbon
dioxide emissions that result from electricity
consumed in Illinois and minimizing sulfur
dioxide, nitrogen oxide, and particulate matter
emissions that adversely affect the citizens of
this State;
(ii) specifically address how the selection of
winning bids takes into account the incremental
environmental benefits resulting from the
procurement, including any existing environmental
benefits that are preserved by the procurements
held under Public Act 99-906 and would have ceased
to exist if the procurements had not been held,
such as the preservation of zero emission
facilities;
(iii) quantify the environmental benefit of
preserving the resources identified in item (ii)
of this subparagraph (C-5), including the

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

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brownfield site photovoltaic projects in
the procurement events specified in item
(ii) of subparagraph (G) of paragraph (1)
of subsection (c) of this Section and,
after January 1, 2015, renewable energy
credits from photovoltaic distributed
generation projects in procurement events
held under subsection (c) of this Section.
Each utility shall enter into binding contractual
arrangements with the winning suppliers.
The procurement described in this subsection
(d-5), including, but not limited to, the execution of
all contracts procured, shall be completed no later
than May 10, 2017. Based on the effective date of
Public Act 99-906, the Agency and Commission may, as
appropriate, modify the various dates and timelines
under this subparagraph and subparagraphs (C) and (D)
of this paragraph (1). The procurement and plan
approval processes required by this subsection (d-5)
shall be conducted in conjunction with the procurement
and plan approval processes required by subsection (c)
of this Section and Section 16-111.5 of the Public
Utilities Act, to the extent practicable.
Notwithstanding whether a procurement event is
conducted under Section 16-111.5 of the Public
Utilities Act, the Agency shall immediately initiate a

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procurement process on June 1, 2017 (the effective
date of Public Act 99-906).
(D) Following the procurement event described in
this paragraph (1) and consistent with subparagraph
(B) of this paragraph (1), the Agency shall calculate
the payments to be made under each contract for the
next delivery year based on the market price index for
that delivery year. The Agency shall publish the
payment calculations no later than May 25, 2017 and
every May 25 thereafter.
(E) Notwithstanding the requirements of this
subsection (d-5), the contracts executed under this
subsection (d-5) shall provide that the zero emission
facility may, as applicable, suspend or terminate
performance under the contracts in the following
instances:
(i) A zero emission facility shall be excused
from its performance under the contract for any
cause beyond the control of the resource,
including, but not restricted to, acts of God,
flood, drought, earthquake, storm, fire,
lightning, epidemic, war, riot, civil disturbance
or disobedience, labor dispute, labor or material
shortage, sabotage, acts of public enemy,
explosions, orders, regulations or restrictions
imposed by governmental, military, or lawfully

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established civilian authorities, which, in any of
the foregoing cases, by exercise of commercially
reasonable efforts the zero emission facility
could not reasonably have been expected to avoid,
and which, by the exercise of commercially
reasonable efforts, it has been unable to
overcome. In such event, the zero emission
facility shall be excused from performance for the
duration of the event, including, but not limited
to, delivery of zero emission credits, and no
payment shall be due to the zero emission facility
during the duration of the event.
(ii) A zero emission facility shall be
permitted to terminate the contract if legislation
is enacted into law by the General Assembly that
imposes or authorizes a new tax, special
assessment, or fee on the generation of
electricity, the ownership or leasehold of a
generating unit, or the privilege or occupation of
such generation, ownership, or leasehold of
generation units by a zero emission facility.
However, the provisions of this item (ii) do not
apply to any generally applicable tax, special
assessment or fee, or requirements imposed by
federal law.
(iii) A zero emission facility shall be

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permitted to terminate the contract in the event
that the resource requires capital expenditures in
excess of $40,000,000 that were neither known nor
reasonably foreseeable at the time it executed the
contract and that a prudent owner or operator of
such resource would not undertake.
(iv) A zero emission facility shall be
permitted to terminate the contract in the event
the Nuclear Regulatory Commission terminates the
resource's license.
(F) If the zero emission facility elects to
terminate a contract under subparagraph (E) of this
paragraph (1), then the Commission shall reopen the
docket in which the Commission approved the zero
emission standard procurement plan under subparagraph
(C) of this paragraph (1) and, after notice and
hearing, enter an order acknowledging the contract
termination election if such termination is consistent
with the provisions of this subsection (d-5).
(2) For purposes of this subsection (d-5), the amount
paid per kilowatthour means the total amount paid for
electric service expressed on a per kilowatthour basis.
For purposes of this subsection (d-5), the total amount
paid for electric service includes, without limitation,
amounts paid for supply, transmission, distribution,
surcharges, and add-on taxes.

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Notwithstanding the requirements of this subsection
(d-5), the contracts executed under this subsection (d-5)
shall provide that the total of zero emission credits
procured under a procurement plan shall be subject to the
limitations of this paragraph (2). For each delivery year,
the contractual volume receiving payments in such year
shall be reduced for all retail customers based on the
amount necessary to limit the net increase that delivery
year to the costs of those credits included in the amounts
paid by eligible retail customers in connection with
electric service to no more than 1.65% of the amount paid
per kilowatthour by eligible retail customers during the
year ending May 31, 2009. The result of this computation
shall apply to and reduce the procurement for all retail
customers, and all those customers shall pay the same
single, uniform cents per kilowatthour charge under
subsection (k) of Section 16-108 of the Public Utilities
Act. To arrive at a maximum dollar amount of zero emission
credits to be paid for the particular delivery year, the
resulting per kilowatthour amount shall be applied to the
actual amount of kilowatthours of electricity delivered by
the electric utility in the delivery year immediately
prior to the procurement, to all retail customers in its
service territory. Unpaid contractual volume for any
delivery year shall be paid in any subsequent delivery
year in which such payments can be made without exceeding

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

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

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(B) The average of the market price indices, as
defined in subparagraph (B) of paragraph (1) of this
subsection (d-5), during the term of the contract,
minus the baseline market price index, as defined in
subparagraph (B) of paragraph (1) of this subsection
(d-5).
If the subtraction yields a negative number, then the
Average ZEC Payment shall be zero.
(4) Cost-effective zero emission credits procured from
zero emission facilities shall satisfy the applicable
definitions set forth in Section 1-10 of this Act.
(5) The electric utility shall retire all zero
emission credits used to comply with the requirements of
this subsection (d-5).
(6) Electric utilities shall be entitled to recover
all of the costs associated with the procurement of zero
emission credits through an automatic adjustment clause
tariff in accordance with subsection (k) and (m) of
Section 16-108 of the Public Utilities Act, and the
contracts executed under this subsection (d-5) shall
provide that the utilities' payment obligations under such
contracts shall be reduced if an adjustment is required
under subsection (m) of Section 16-108 of the Public
Utilities Act.
(7) This subsection (d-5) shall become inoperative on
January 1, 2028.

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(d-10) Nuclear Plant Assistance; carbon mitigation
credits.
(1) The General Assembly finds:
(A) The health, welfare, and prosperity of all
Illinois citizens require that the State of Illinois act
to avoid and not increase carbon emissions from electric
generation sources while continuing to ensure affordable,
stable, and reliable electricity to all citizens.
(B) Absent immediate action by the State to preserve
existing carbon-free energy resources, those resources may
retire, and the electric generation needs of Illinois'
retail customers may be met instead by facilities that
emit significant amounts of carbon pollution and other
harmful air pollutants at a high social and economic cost
until Illinois is able to develop other forms of clean
energy.
(C) The General Assembly finds that nuclear power
generation is necessary for the State's transition to 100%
clean energy, and ensuring continued operation of nuclear
plants advances environmental and public health interests
through providing carbon-free electricity while reducing
the air pollution profile of the Illinois energy
generation fleet.
(D) The clean energy attributes of nuclear generation
facilities support the State in its efforts to achieve
100% clean energy.

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(E) The State currently invests in various forms of
clean energy, including, but not limited to, renewable
energy, energy efficiency, and low-emission vehicles,
among others.
(F) The Environmental Protection Agency commissioned
an independent audit which provided a detailed assessment
of the financial condition of the Illinois nuclear fleet
to evaluate its financial viability and whether the
environmental benefits of such resources were at risk. The
report identified the risk of losing the environmental
benefits of several specific nuclear units. The report
also identified that the LaSalle County Generating Station
will continue to operate through 2026 and therefore is not
eligible to participate in the carbon mitigation credit
program.
(G) Nuclear plants provide carbon-free energy, which
helps to avoid many health-related negative impacts for
Illinois residents.
(H) The procurement of carbon mitigation credits
representing the environmental benefits of carbon-free
generation will further the State's efforts at achieving
100% clean energy and decarbonizing the electricity sector
in a safe, reliable, and affordable manner. Further, the
procurement of carbon emission credits will enhance the
health and welfare of Illinois residents through decreased
reliance on more highly polluting generation.

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(I) The General Assembly therefore finds it necessary
to establish carbon mitigation credits to ensure decreased
reliance on more carbon-intensive energy resources, for
transitioning to a fully decarbonized electricity sector,
and to help ensure health and welfare of the State's
residents.
(2) As used in this subsection:
"Baseline costs" means costs used to establish a customer
protection cap that have been evaluated through an independent
audit of a carbon-free energy resource conducted by the
Environmental Protection Agency that evaluated projected
annual costs for operation and maintenance expenses; fully
allocated overhead costs, which shall be allocated using the
methodology developed by the Institute for Nuclear Power
Operations; fuel expenditures; nonfuel capital expenditures;
spent fuel expenditures; a return on working capital; the cost
of operational and market risks that could be avoided by
ceasing operation; and any other costs necessary for continued
operations, provided that "necessary" means, for purposes of
this definition, that the costs could reasonably be avoided
only by ceasing operations of the carbon-free energy resource.
"Carbon mitigation credit" means a tradable credit that
represents the carbon emission reduction attributes of one
megawatt-hour of energy produced from a carbon-free energy
resource.
"Carbon-free energy resource" means a generation facility

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that: (1) is fueled by nuclear power; and (2) is
interconnected to PJM Interconnection, LLC.
(3) Procurement.
(A) Beginning with the delivery year commencing on
June 1, 2022, the Agency shall, for electric utilities
serving at least 3,000,000 retail customers in the State,
seek to procure contracts for no more than approximately
54,500,000 cost-effective carbon mitigation credits from
carbon-free energy resources because such credits are
necessary to support current levels of carbon-free energy
generation and ensure the State meets its carbon dioxide
emissions reduction goals. The Agency shall not make a
partial award of a contract for carbon mitigation credits
covering a fractional amount of a carbon-free energy
resource's projected output.
(B) Each carbon-free energy resource that intends to
participate in a procurement shall be required to submit
to the Agency the following information for the resource
on or before the date established by the Agency:
(i) the in-service date and remaining useful life
of the carbon-free energy resource;
(ii) the amount of power generated annually for
each of the past 10 years, which shall be used to
determine the capability of each facility;
(iii) a commitment to be reflected in any contract
entered into pursuant to this subsection (d-10) to

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continue operating the carbon-free energy resource at
a capacity factor of at least 88% annually on average
for the duration of the contract or contracts executed
under the procurement held under this subsection
(d-10), except in an instance described in
subparagraph (E) of paragraph (1) of subsection (d-5)
of this Section or made impracticable as a result of
compliance with law or regulation;
(iv) financial need and the risk of loss of the
environmental benefits of such resource, which shall
include the following information:
(I) the carbon-free energy resource's cost
projections, expressed on a per megawatt-hour
basis, over the next 5 delivery years, which shall
include the following: operation and maintenance
expenses; fully allocated overhead costs, which
shall be allocated using the methodology developed
by the Institute for Nuclear Power Operations;
fuel expenditures; nonfuel capital expenditures;
spent fuel expenditures; a return on working
capital; the cost of operational and market risks
that could be avoided by ceasing operation; and
any other costs necessary for continued
operations, provided that "necessary" means, for
purposes of this subitem (I), that the costs could
reasonably be avoided only by ceasing operations

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of the carbon-free energy resource; and
(II) the carbon-free energy resource's revenue
projections, including energy, capacity, ancillary
services, any other direct State support, known or
anticipated federal attribute credits, known or
anticipated tax credits, and any other direct
federal support.
The information described in this subparagraph (B) may
be submitted on a confidential basis and shall be treated
and maintained by the Agency, the procurement
administrator, and the Commission as confidential and
proprietary and exempt from disclosure under subparagraphs
(a) and (g) of paragraph (1) of Section 7 of the Freedom of
Information Act. The Office of the Attorney General shall
have access to, and maintain the confidentiality of, such
information pursuant to Section 6.5 of the Attorney
General Act.
(C) The Agency shall solicit bids for the contracts
described in this subsection (d-10) from carbon-free
energy resources that have satisfied the requirements of
subparagraph (B) of this paragraph (3). The contracts
procured pursuant to a procurement event shall reflect,
and be subject to, the following terms, requirements, and
limitations:
(i) Contracts are for delivery of carbon
mitigation credits, and are not energy or capacity

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sales contracts requiring physical delivery. Pursuant
to item (iii), contract payments shall fully deduct
the value of any monetized federal production tax
credits, credits issued pursuant to a federal clean
energy standard, and other federal credits if
applicable.
(ii) Contracts for carbon mitigation credits shall
commence with the delivery year beginning on June 1,
2022 and shall be for a term of 5 delivery years
concluding on May 31, 2027.
(iii) The price per carbon mitigation credit to be
paid under a contract for a given delivery year shall
be equal to an accepted bid price less the sum of:
(I) one of the following energy price indices,
selected by the bidder at the time of the bid for
the term of the contract:
(aa) the weighted-average hourly day-ahead
price for the applicable delivery year at the
busbar of all resources procured pursuant to
this subsection (d-10), weighted by actual
production from the resources; or
(bb) the projected energy price for the
PJM Interconnection, LLC Northern Illinois Hub
for the applicable delivery year determined
according to subitem (aa) of item (iii) of
subparagraph (B) of paragraph (1) of

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subsection (d-5).
(II) the Base Residual Auction Capacity Price
for the ComEd zone as determined by PJM
Interconnection, LLC, divided by 24 hours per day,
for the applicable delivery year for the first 3
delivery years, and then any subsequent delivery
years unless the PJM Interconnection, LLC applies
the Minimum Offer Price Rule to participating
carbon-free energy resources because they supply
carbon mitigation credits pursuant to this Section
at which time, upon notice by the carbon-free
energy resource to the Commission and subject to
the Commission's confirmation, the value under
this subitem shall be zero, as further described
in the carbon mitigation credit procurement plan;
and
(III) any value of monetized federal tax
credits, direct payments, or similar subsidy
provided to the carbon-free energy resource from
any unit of government that is not already
reflected in energy prices.
If the price-per-megawatt-hour calculation
performed under item (iii) of this subparagraph (C)
for a given delivery year results in a net positive
value, then the electric utility counterparty to the
contract shall multiply such net value by the

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

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(II) For the delivery year beginning June 1,
2023, the baseline costs shall be an amount equal
to $32.50 per megawatt-hour.
(III) For the delivery year beginning June 1,
2024, the baseline costs shall be an amount equal
to $33.43 per megawatt-hour.
(IV) For the delivery year beginning June 1,
2025, the baseline costs shall be an amount equal
to $33.50 per megawatt-hour.
(V) For the delivery year beginning June 1,
2026, the baseline costs shall be an amount equal
to $34.50 per megawatt-hour.
An Environmental Protection Agency consultant
forecast, included in a report issued April 14, 2021,
projects that a carbon-free energy resource has the
opportunity to earn on average approximately $30.28
per megawatt-hour, for the sale of energy and capacity
during the time period between 2022 and 2027.
Therefore, the sale of carbon mitigation credits
provides the opportunity to receive an additional
amount per megawatt-hour in addition to the projected
prices for energy and capacity.
Although actual energy and capacity prices may
vary from year-to-year, the General Assembly finds
that this customer protection cap will help ensure
that the cost of carbon mitigation credits will be

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less than its value, based upon the social cost of
carbon identified in the Technical Support Document
issued in February 2021 by the U.S. Interagency
Working Group on Social Cost of Greenhouse Gases and
the PJM Interconnection, LLC carbon dioxide marginal
emission rate for 2020, and that a carbon-free energy
resource receiving payment for carbon mitigation
credits receives no more than necessary to keep those
units in operation.
(D) No later than 7 days after the effective date of
this amendatory Act of the 102nd General Assembly, the
Agency shall publish its proposed carbon mitigation credit
procurement plan. The Plan shall provide that winning bids
shall be selected by taking into consideration which
resources best match public interest criteria that
include, but are not limited to, minimizing carbon dioxide
emissions that result from electricity consumed in
Illinois and minimizing sulfur dioxide, nitrogen oxide,
and particulate matter emissions that adversely affect the
citizens of this State. The selection of winning bids
shall also take into account the incremental environmental
benefits resulting from the procurement or procurements,
such as any existing environmental benefits that are
preserved by a procurement held under this subsection
(d-10) and would cease to exist if the procurement were
not held, including the preservation of carbon-free energy

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resources. For those bidders having the same public
interest criteria score, the relative ranking of such
bidders shall be determined by price. The Plan shall
describe in detail how each public interest factor shall
be considered and weighted in the bid selection process to
ensure that the public interest criteria are applied to
the procurement. The Plan shall, to the extent practical
and permissible by federal law, ensure that successful
bidders make commercially reasonable efforts to apply for
federal tax credits, direct payments, or similar subsidy
programs that support carbon-free generation and for which
the successful bidder is eligible. Upon publishing of the
carbon mitigation credit procurement plan, copies of the
plan shall be posted and made publicly available on the
Agency's website. All interested parties shall have 7 days
following the date of posting to provide comment to the
Agency on the plan. All comments shall be posted to the
Agency's website. Following the end of the comment period,
but no more than 19 days later than the effective date of
this amendatory Act of the 102nd General Assembly, the
Agency shall revise the plan as necessary based on the
comments received and file its carbon mitigation credit
procurement plan with the Commission.
(E) If the Commission determines that the plan is
likely to result in the procurement of cost-effective
carbon mitigation credits, then the Commission shall,

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after notice and hearing and opportunity for comment, but
no later than 42 days after the Agency filed the plan,
approve the plan or approve it with modification. For
purposes of this subsection (d-10), "cost-effective" means
carbon mitigation credits that are procured from
carbon-free energy resources at prices that are within the
limits specified in this paragraph (3). As part of the
Commission's review and acceptance or rejection of the
procurement results, the Commission shall, in its public
notice of successful bidders:
(i) identify how the selected carbon-free energy
resources satisfy the public interest criteria
described in this paragraph (3) of minimizing carbon
dioxide emissions that result from electricity
consumed in Illinois and minimizing sulfur dioxide,
nitrogen oxide, and particulate matter emissions that
adversely affect the citizens of this State;
(ii) specifically address how the selection of
carbon-free energy resources takes into account the
incremental environmental benefits resulting from the
procurement, including any existing environmental
benefits that are preserved by the procurements held
under this amendatory Act of the 102nd General
Assembly and would have ceased to exist if the
procurements had not been held, such as the
preservation of carbon-free energy resources;

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(iii) quantify the environmental benefit of
preserving the carbon-free energy resources procured
pursuant to this subsection (d-10), including the
following:
(I) an assessment value of avoided greenhouse
gas emissions measured as the product of the
carbon-free energy resources' output over the
contract term, using generally accepted
methodologies for the valuation of avoided
emissions; and
(II) an assessment of costs of replacement
with other carbon-free energy resources and
renewable energy resources, including wind and
photovoltaic generation, based upon an assessment
of the prices paid for renewable energy credits
through programs and procurements conducted
pursuant to subsection (c) of Section 1-75 of this
Act, and the additional storage necessary to
produce the same or similar capability of matching
customer usage patterns.
(F) The procurements described in this paragraph (3),
including, but not limited to, the execution of all
contracts procured, shall be completed no later than
December 3, 2021. The procurement and plan approval
processes required by this paragraph (3) shall be
conducted in conjunction with the procurement and plan

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approval processes required by Section 16-111.5 of the
Public Utilities Act, to the extent practicable. However,
the Agency and Commission may, as appropriate, modify the
various dates and timelines under this subparagraph and
subparagraphs (D) and (E) of this paragraph (3) to meet
the December 3, 2021 contract execution deadline.
Following the completion of such procurements, and
consistent with this paragraph (3), the Agency shall
calculate the payments to be made under each contract in a
timely fashion.
(F-1) Costs incurred by the electric utility pursuant
to a contract authorized by this subsection (d-10) shall
be deemed prudently incurred and reasonable in amount, and
the electric utility shall be entitled to full cost
recovery pursuant to a tariff or tariffs filed with the
Commission.
(G) The counterparty electric utility shall retire all
carbon mitigation credits used to comply with the
requirements of this subsection (d-10).
(H) If a carbon-free energy resource is sold to
another owner, the rights, obligations, and commitments
under this subsection (d-10) shall continue to the
subsequent owner.
(I) This subsection (d-10) shall become inoperative on
January 1, 2028.
(e) The draft procurement plans are subject to public

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comment, as required by Section 16-111.5 of the Public
Utilities Act.
(f) The Agency shall submit the final procurement plan to
the Commission. The Agency shall revise a procurement plan if
the Commission determines that it does not meet the standards
set forth in Section 16-111.5 of the Public Utilities Act.
(g) The Agency shall assess fees to each affected utility
to recover the costs incurred in preparation of the annual
procurement plan for the utility.
(h) The Agency shall assess fees to each bidder to recover
the costs incurred in connection with a competitive
procurement process.
(i) A renewable energy credit, carbon emission credit,
zero emission credit, or carbon mitigation credit can only be
used once to comply with a single portfolio or other standard
as set forth in subsection (c), subsection (d), or subsection
(d-5) of this Section, respectively. A renewable energy
credit, carbon emission credit, zero emission credit, or
carbon mitigation credit cannot be used to satisfy the
requirements of more than one standard. If more than one type
of credit is issued for the same megawatt hour of energy, only
one credit can be used to satisfy the requirements of a single
standard. After such use, the credit must be retired together
with any other credits issued for the same megawatt hour of
energy.
(Source: P.A. 102-662, eff. 9-15-21; 103-380, eff. 1-1-24;

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103-580, eff. 12-8-23; 103-1066, eff. 2-20-25.)
(Text of Section after amendment by P.A. 104-458)
Sec. 1-75. Planning and Procurement Bureau. The Planning
and Procurement Bureau has the following duties and
responsibilities:
(a) The Planning and Procurement Bureau shall each year,
beginning in 2008, develop procurement plans and conduct
competitive procurement processes in accordance with the
requirements of Section 16-111.5 of the Public Utilities Act
for the eligible retail customers of electric utilities that
on December 31, 2005 provided electric service to at least
100,000 customers in Illinois. Beginning with the delivery
year commencing on June 1, 2017, the Planning and Procurement
Bureau shall develop plans and processes for the procurement
of zero emission credits from zero emission facilities in
accordance with the requirements of subsection (d-5) of this
Section. Beginning on the effective date of this amendatory
Act of the 102nd General Assembly, the Planning and
Procurement Bureau shall develop plans and processes for the
procurement of carbon mitigation credits from carbon-free
energy resources in accordance with the requirements of
subsection (d-10) of this Section. The Planning and
Procurement Bureau shall also develop procurement plans and
conduct competitive procurement processes in accordance with
the requirements of Section 16-111.5 of the Public Utilities

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Act for the eligible retail customers of small
multi-jurisdictional electric utilities that (i) on December
31, 2005 served less than 100,000 customers in Illinois and
(ii) request a procurement plan for their Illinois
jurisdictional load. This Section shall not apply to a small
multi-jurisdictional utility until such time as a small
multi-jurisdictional utility requests the Agency to prepare a
procurement plan for their Illinois jurisdictional load. For
the purposes of this Section, the term "eligible retail
customers" has the same definition as found in Section
16-111.5(a) of the Public Utilities Act.
Beginning with the plan or plans to be implemented in the
2017 delivery year, the Agency shall no longer include the
procurement of renewable energy resources in the annual
procurement plans required by this subsection (a), except as
provided in subsection (q) of Section 16-111.5 of the Public
Utilities Act, and shall instead develop a long-term renewable
resources procurement plan in accordance with subsection (c)
of this Section and Section 16-111.5 of the Public Utilities
Act.
In accordance with subsection (c-5) of this Section, the
Planning and Procurement Bureau shall oversee the procurement
by electric utilities that served more than 300,000 retail
customers in this State as of January 1, 2019 of renewable
energy credits from new utility-scale solar projects to be
installed, along with energy storage facilities, at or

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adjacent to the sites of electric generating facilities that,
as of January 1, 2016, burned coal as their primary fuel
source.
(1) The Agency shall each year, beginning in 2008, as
needed, issue a request for qualifications for experts or
expert consulting firms to develop the procurement plans
in accordance with Section 16-111.5 of the Public
Utilities Act. In order to qualify an expert or expert
consulting firm must have:
(A) direct previous experience assembling
large-scale power supply plans or portfolios for
end-use customers;
(B) an advanced degree in economics, mathematics,
engineering, risk management, or a related area of
study;
(C) 10 years of experience in the electricity
sector, including managing supply risk;
(D) expertise in wholesale electricity market
rules, including those established by the Federal
Energy Regulatory Commission and regional transmission
organizations;
(E) expertise in credit protocols and familiarity
with contract protocols;
(F) adequate resources to perform and fulfill the
required functions and responsibilities; and
(G) the absence of a conflict of interest and

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

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

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appeal of the Commission's ruling.
(4) The Agency shall issue requests for proposals to
the qualified experts or expert consulting firms to
develop a procurement plan for the affected utilities and
to serve as procurement administrator.
(5) The Agency shall select an expert or expert
consulting firm to develop procurement plans based on the
proposals submitted and shall award contracts of up to 5
years to those selected.
(6) The Agency shall select an expert or expert
consulting firm, with approval of the Commission, to serve
as procurement administrator based on the proposals
submitted. If the Commission rejects, within 5 days, the
Agency's selection, the Agency shall submit another
recommendation within 3 days based on the proposals
submitted. The Agency shall award a 5-year contract to the
expert or expert consulting firm so selected with
Commission approval.
(b) The experts or expert consulting firms retained by the
Agency shall, as appropriate, prepare procurement plans, and
conduct a competitive procurement process as prescribed in
Section 16-111.5 of the Public Utilities Act, to ensure
adequate, reliable, affordable, efficient, and environmentally
sustainable electric service at the lowest total cost over
time, taking into account any benefits of price stability, for
eligible retail customers of electric utilities that on

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December 31, 2005 provided electric service to at least
100,000 customers in the State of Illinois, and for eligible
Illinois retail customers of small multi-jurisdictional
electric utilities that (i) on December 31, 2005 served less
than 100,000 customers in Illinois and (ii) request a
procurement plan for their Illinois jurisdictional load.
(c) Renewable portfolio standard.
(1)(A) The Agency shall develop a long-term renewable
resources procurement plan that shall include procurement
programs and competitive procurement events necessary to
meet the goals set forth in this subsection (c). The
initial long-term renewable resources procurement plan
shall be released for comment no later than 160 days after
June 1, 2017 (the effective date of Public Act 99-906).
The Agency shall review, and may revise on an expedited
basis, the long-term renewable resources procurement plan
at least every 2 years, which shall be conducted in
conjunction with the procurement plan under Section
16-111.5 of the Public Utilities Act to the extent
practicable to minimize administrative expense. No later
than 120 days after the effective date of this amendatory
Act of the 103rd General Assembly, the Agency shall
release for comment a revision to the long-term renewable
resources procurement plan, updating elements of the most
recently approved plan as needed to comply with this
amendatory Act of the 103rd General Assembly, and any

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long-term renewable resources procurement plan update
published by the Agency but not yet approved by the
Illinois Commerce Commission shall be withdrawn. The
long-term renewable resources procurement plans shall be
subject to review and approval by the Commission under
Section 16-111.5 of the Public Utilities Act.
(B) Subject to subparagraph (F) of this paragraph (1),
the long-term renewable resources procurement plan shall
attempt to meet the goals for procurement of renewable
energy credits at levels of at least the following overall
percentages: 13% by the 2017 delivery year; increasing by
at least 1.5% each delivery year thereafter to at least
25% by the 2025 delivery year; increasing by at least 3%
each delivery year thereafter to at least 40% by the 2030
delivery year, and continuing at no less than 40% for each
delivery year thereafter. The Agency shall attempt to
procure 50% by delivery year 2040. The Agency shall
determine the annual increase between delivery year 2030
and delivery year 2040, if any, taking into account energy
demand, other energy resources, and other public policy
goals. In the event of a conflict between these goals and
the new wind, new photovoltaic, new geothermal heating and
cooling, and hydropower procurement requirements described
in items (i) through (iii) of subparagraph (C) of this
paragraph (1), the long-term plan shall prioritize
compliance with the new wind, new photovoltaic, new

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geothermal heating and cooling, and hydropower procurement
requirements described in items (i) through (iii) of
subparagraph (C) of this paragraph (1) over the annual
percentage targets described in this subparagraph (B). The
Agency shall not comply with the annual percentage targets
described in this subparagraph (B) by procuring renewable
energy credits that are unlikely to lead to the
development of new renewable resources or new, modernized,
or retooled hydropower facilities.
For the delivery year beginning June 1, 2017, the
procurement plan shall attempt to include, subject to the
prioritization outlined in this subparagraph (B),
cost-effective renewable energy resources equal to at
least 13% of each utility's load for eligible retail
customers and 13% of the applicable portion of each
utility's load for retail customers who are not eligible
retail customers, which applicable portion shall equal 50%
of the utility's load for retail customers who are not
eligible retail customers on February 28, 2017.
For the delivery year beginning June 1, 2018, the
procurement plan shall attempt to include, subject to the
prioritization outlined in this subparagraph (B),
cost-effective renewable energy resources equal to at
least 14.5% of each utility's load for eligible retail
customers and 14.5% of the applicable portion of each
utility's load for retail customers who are not eligible

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retail customers, which applicable portion shall equal 75%
of the utility's load for retail customers who are not
eligible retail customers on February 28, 2017.
For the delivery year beginning June 1, 2019, and for
each year thereafter, the procurement plans shall attempt
to include, subject to the prioritization outlined in this
subparagraph (B), cost-effective renewable energy
resources equal to a minimum percentage of each utility's
load for all retail customers as follows: 16% by June 1,
2019; increasing by 1.5% each year thereafter to 25% by
June 1, 2025; and 25% by June 1, 2026; increasing by at
least 3% each delivery year thereafter to at least 40% by
the 2030 delivery year, and continuing at no less than 40%
for each delivery year thereafter. The Agency shall
attempt to procure 50% by delivery year 2040. The Agency
shall determine the annual increase between delivery year
2030 and delivery year 2040, if any, taking into account
energy demand, other energy resources, and other public
policy goals.
For each delivery year, the Agency shall first
recognize each utility's obligations for that delivery
year under existing contracts. Any renewable energy
credits under existing contracts, including renewable
energy credits as part of renewable energy resources,
shall be used to meet the goals set forth in this
subsection (c) for the delivery year.

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(C) The long-term renewable resources procurement plan
described in subparagraph (A) of this paragraph (1) shall
include the procurement of renewable energy credits from
new projects pursuant to the following terms:
(i) At least 10,000,000 renewable energy credits
delivered annually by the end of the 2021 delivery
year, and increasing ratably to reach 45,000,000
renewable energy credits delivered annually from new
wind and solar projects, from repowered wind projects,
or from retooled hydropower facilities by the end of
delivery year 2030 such that the goals in subparagraph
(B) of this paragraph (1) are met entirely by
procurements of renewable energy credits from new wind
and photovoltaic projects. Of that amount, to the
extent possible, the Agency shall endeavor to procure
45% from new and repowered wind and hydropower
projects and shall procure at least 55% from
photovoltaic projects. Of the amount to be procured
from photovoltaic projects, the Agency shall procure:
at least 50% from solar photovoltaic projects using
the program outlined in subparagraph (K) of this
paragraph (1) from distributed renewable energy
generation devices or community renewable generation
projects; at least 47% from utility-scale solar
projects; at least 3% from brownfield site
photovoltaic projects that are not community renewable

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generation projects. The Agency may propose
adjustments to these percentages, including
establishing percentage-based goals for the
procurement of renewable energy credits from
modernized or retooled hydropower facilities and
repowered wind projects, through its long-term
renewable resources plan described in subparagraph (A)
of this paragraph (1) as necessary based on developer
interest, market conditions, budget considerations,
resource adequacy needs, or other factors.
Notwithstanding the percentage-based goals as
described in this Section, the Agency shall develop a
Geothermal Homes and Businesses Program for the
procurement of renewable energy credits from
geothermal heating and cooling systems.
In developing the long-term renewable resources
procurement plan, the Agency shall consider other
approaches, in addition to competitive procurements,
that can be used to procure renewable energy credits
from brownfield site photovoltaic projects and thereby
help return blighted or contaminated land to
productive use while enhancing public health and the
well-being of Illinois residents, including those in
environmental justice communities, as defined using
existing methodologies and findings used by the Agency
and its Administrator in its Illinois Solar for All

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Program. The Agency shall also consider other
approaches, in addition to competitive procurements,
to procure renewable energy credits from new and
existing hydropower facilities to support the
development and maintenance of these facilities. The
Agency shall explore options to convert existing dams
but shall not consider approaches to develop new dams
where they do not already exist. To encourage the
continued operation of utility-scale wind projects,
the Agency shall consider and may propose other
approaches in addition to competitive procurements to
procure renewable energy credits from repowered wind
projects.
(ii) In any given delivery year, if forecasted
expenses are less than the maximum budget available
under subparagraph (E) of this paragraph (1), the
Agency shall continue to procure new renewable energy
credits until that budget is exhausted in the manner
outlined in item (i) of this subparagraph (C).
(iii) For purposes of this Section:
"New wind projects" means wind renewable energy
facilities that are energized after June 1, 2017 for
the delivery year commencing June 1, 2017.
"New photovoltaic projects" means photovoltaic
renewable energy facilities that are energized after
June 1, 2017. Photovoltaic projects developed under

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Section 1-56 of this Act shall not apply towards the
new photovoltaic project requirements in this
subparagraph (C).
"Repowered wind projects" means utility-scale wind
projects featuring the removal, replacement, or
expansion of turbines at an existing project site, as
defined in the long-term renewable resources
procurement plan, after the effective date of this
amendatory Act of the 103rd General Assembly.
Renewable energy credit contract awards used to
support repowered wind projects shall only cover the
incremental increase in facility electricity
production resultant from repowering.
"Geothermal heating and cooling system" means a
system located in this State that meets all of the
following requirements:
(I) the system exchanges thermal energy from
groundwater or a shallow ground source to generate
thermal energy through an electric geothermal heat
pump or a system of electric geothermal heat pumps
interconnected with any geothermal extraction
facility that is (1) a closed loop or a series of
closed loop systems in which fluid is permanently
confined within a pipe or tubing and does not come
in contact with the outside environment or (2) an
open loop system in which ground or surface water

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is circulated in an environmentally safe manner
directly into the facility and returned to the
same aquifer or surface water source;
(II) to the extent applicable and practicable,
the system meets or exceeds federal Energy Star
product specification standards for Geothermal
Heat Pumps established on January 1, 2012, as
clarified by the Environmental Protection Agency
guidance document released on February 28, 2012
entitled "Clarification to the Geothermal Heat
Pump Verification Testing Requirements and Basic
Model Group Definition", or any successor
standards that meet or exceed these standards;
(III) the system replaces or displaces less
efficient space or water heating systems,
regardless of fuel type;
(IV) the system replaces or displaces less
efficient space cooling systems, when applicable;
(V) the system does not feed electricity back
to the grid, as defined at the level of the
geothermal heat pump; and
(VI) the system became operational on or after
the effective date of this amendatory Act of the
104th General Assembly.
For purposes of calculating whether the Agency has
procured enough new wind and solar renewable energy

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credits required by this subparagraph (C), renewable
energy facilities that have a multi-year renewable
energy credit delivery contract with the utility
through at least delivery year 2030 shall be
considered new, however no renewable energy credits
from contracts entered into before June 1, 2021 shall
be used to calculate whether the Agency has procured
the correct proportion of new wind and new solar
contracts described in this subparagraph (C) for
delivery year 2021 and thereafter.
(iv) The Agency may implement additional measures,
including eligibility requirements, to ensure that new
wind projects and new photovoltaic projects supported
through renewable energy credit contract awards are a
result of a contract award and are otherwise developed
pursuant to the financial certainty provided through a
contract award.
(D) Renewable energy credits shall be cost effective.
For purposes of this subsection (c), "cost effective"
means that the costs of procuring renewable energy
resources do not cause the limit stated in subparagraph
(E) of this paragraph (1) to be exceeded and, for
renewable energy credits procured through a competitive
procurement event, do not exceed benchmarks based on
market prices for like products in the region. For
purposes of this subsection (c), "like products" means

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contracts for renewable energy credits from the same or
substantially similar technology, same or substantially
similar vintage (new or existing), the same or
substantially similar quantity, and the same or
substantially similar contract length and structure.
Benchmarks shall reflect development, financing, or
related costs resulting from requirements imposed through
other provisions of State law, including, but not limited
to, requirements in subparagraphs (P) and (Q) of this
paragraph (1) and the Renewable Energy Facilities
Agricultural Impact Mitigation Act. Confidential
benchmarks shall be developed by the procurement
administrator, in consultation with the Commission staff,
Agency staff, and the procurement monitor and shall be
subject to Commission review and approval. If price
benchmarks for like products in the region are not
available, the procurement administrator shall establish
price benchmarks based on publicly available data on
regional technology costs and expected current and future
regional energy prices. The benchmarks in this Section
shall not be used to curtail or otherwise reduce
contractual obligations entered into by or through the
Agency prior to June 1, 2017 (the effective date of Public
Act 99-906).
(E) For purposes of this subsection (c), the required
procurement of cost-effective renewable energy resources

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for a particular year commencing prior to June 1, 2017
shall be measured as a percentage of the actual amount of
electricity (megawatt-hours) supplied by the electric
utility to eligible retail customers in the delivery year
ending immediately prior to the procurement, and, for
delivery years commencing on and after June 1, 2017, the
required procurement of cost-effective renewable energy
resources for a particular year shall be measured as a
percentage of the actual amount of electricity
(megawatt-hours) delivered by the electric utility in the
delivery year ending immediately prior to the procurement,
to all retail customers in its service territory. For
purposes of this subsection (c), the amount paid per
kilowatthour means the total amount paid for electric
service expressed on a per kilowatthour basis. For
purposes of this subsection (c), the total amount paid for
electric service includes without limitation amounts paid
for supply, transmission, capacity, distribution,
surcharges, and add-on taxes.
Notwithstanding the requirements of this subsection
(c), and except as provided in subparagraph (E-5) of
paragraph (1) of this subsection (c) or except as
otherwise authorized by the Commission in its approval of
the integrated resource plan under Section 16-202 of the
Public Utilities Act, the total of renewable energy
resources procured under the procurement plan for any

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single year shall be subject to the limitations of this
subparagraph (E). Such procurement shall be reduced for
all retail customers based on the amount necessary to
limit the annual estimated average net increase due to the
costs of these resources included in the amounts paid by
eligible retail customers in connection with electric
service to no more than 4.25% of the amount paid per
kilowatthour by those customers during the year ending May
31, 2009, adjusted annually for inflation starting with
the first adjustment in the delivery year commencing June
1, 2026. For the purposes of this Section, the inflation
adjustment shall not be accrued or applied retroactively
prior to the effective date of this amendatory Act of the
104th General Assembly and shall apply prospectively
starting in 2025. The limitation shall be increased by an
additional 1.65 percentage points of the amount paid per
kilowatthour by eligible retail customers during the year
ending May 31, 2009 starting with the delivery year
commencing June 1, 2027. To arrive at a maximum dollar
amount of renewable energy resources to be procured for
the particular delivery year, the resulting per
kilowatthour amount shall be applied to the actual amount
of kilowatthours of electricity delivered, or applicable
portion of such amount as specified in paragraph (1) of
this subsection (c), as applicable, by the electric
utility in the delivery year immediately prior to the

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procurement to all retail customers in its service
territory. The calculations required by this subparagraph
(E) shall be made only once for each delivery year at the
time that the renewable energy resources are procured.
Once the determination as to the amount of renewable
energy resources to procure is made based on the
calculations set forth in this subparagraph (E) and the
contracts procuring those amounts are executed between the
seller and applicable electric utility, no subsequent rate
impact determinations shall be made and no adjustments to
those contract amounts shall be allowed. As provided in
subparagraph (E-5) of paragraph (1) of this subsection
(c), the seller shall be entitled to full, prompt, and
uninterrupted payment under the applicable contract
notwithstanding the application of this subparagraph (E),
and all costs incurred under such contracts shall be fully
recoverable by the electric utility as provided in this
Section.
(E-5) If, for a particular delivery year, the
limitation on the amount of renewable energy resources to
be procured, as calculated pursuant to subparagraph (E) of
paragraph (1) of this subsection (c), would result in an
insufficient collection of funds to fully pay amounts due
to a seller under existing contracts executed under this
Section or executed under Section 1-56 of this Act, then
the following provisions shall apply to ensure full and

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uninterrupted payment is made to such seller or sellers:
(i) If the electric utility has retained unspent
funds in an interest-bearing account as prescribed in
subsection (k) of Section 16-108 of the Public
Utilities Act, then the utility shall use those funds
to remit full payment to the sellers to ensure prompt
and uninterrupted payment of existing contractual
obligation.
(ii) If the funds described in item (i) of this
subparagraph (E-5) are insufficient to satisfy all
existing contractual obligations, then the electric
utility shall, nonetheless, remit full payment to the
sellers to ensure prompt and uninterrupted payment of
existing contractual obligations, provided that the
full costs shall be recoverable by the utility in
accordance with part (ee) of item (iv) of this
subsection (E-5).
(iii) The Agency shall promptly notify the
Commission that existing contractual obligations are
reasonably expected to exceed the maximum collection
authorized under subparagraph (E) of paragraph (1) of
this subsection (c) for the applicable delivery year.
The Agency shall also explain and confirm how the
operation of items (i) and (ii) of this subparagraph
(E-5) ensures that the electric utility will continue
to make prompt and uninterrupted payment under

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existing contractual obligations. The Agency shall
provide this information to the Commission through a
notice filed in the Commission docket approving the
Agency's operative Long-Term Renewable Resources
Procurement Plan that includes the applicable delivery
year.
(iv) The Agency shall suspend or reduce new
contract awards for the procurement of renewable
energy credits until an Agency determination is made
under subparagraph (E) that additional procurements
would not cause the rate impact limitation of
subparagraph (E) to be exceeded. At least once
annually after the notice provided for in item (iii)
of this subparagraph (E-5) is made, the Agency shall
analyze existing contract obligations, projected
prices for indexed renewable energy credit contracts
executed under item (v) of subparagraph (G) of
paragraph (1) of subsection (c) of Section 1-75 of
this Act, and expected collections authorized under
subparagraph (E) to determine whether and to what
extent the limitations of subparagraph (E) would be
exceeded by additional renewable energy credit
procurement contract awards.
(aa) If the Agency determines that additional
renewable energy credit procurement contract
awards could be made without exceeding the

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limitations of subparagraph (E), then the
procurements shall be authorized at a scale
determined not to exceed the limitations of
subparagraph (E) in a manner consistent with the
priorities of this Section.
(bb) If the Agency determines that additional
renewable energy credit procurement contract
awards cannot be made without exceeding the
limitations of subparagraph (E), then the Agency
shall suspend any new contract awards for the
procurement of renewable energy credits until a
new rate impact determination is made under
subparagraph (E).
(cc) Agency determinations made under this
item (iv) shall be detailed and comprehensive and,
if not made through the Agency's Long-Term
Renewable Resources Procurement Plan, shall be
filed as a compliance filing in the most recent
docketed proceeding approving the Agency's
Long-Term Renewable Resources Procurement Plan.
(dd) With respect to the procurement of
renewable energy credits authorized through
programs administered under subsection (b) of
Section 1-56 and subparagraphs (K) through (M) of
paragraph (1) of subsection (k) of Section 1-75 of
this Act, the award of contracts for the

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procurement of renewable energy credits shall be
suspended or reduced only at the conclusion of the
program year in which the notice provided for
under item (iii) of this subparagraph (E-5) is
made.
(ee) The contract shall provide that, so long
as at least one of: (i) the cost recovery
mechanisms referenced in subsection (k) of Section
16-108 and subsection (l) of Section 16-111.5 of
the Public Utilities Act remains in full force
without limitation or (ii) the utility is
otherwise authorized and or entitled to full,
prompt, and uninterrupted recovery of its costs
through any other mechanism, then such seller
shall be entitled to full, prompt, and
uninterrupted payment under the applicable
contract notwithstanding the application of this
subparagraph (E).
(F) If the limitation on the amount of renewable
energy resources procured in subparagraph (E) of this
paragraph (1) prevents the Agency from meeting all of the
goals in this subsection (c), the Agency's long-term plan
shall prioritize compliance with the requirements of this
subsection (c) regarding renewable energy credits in the
following order:
(i) renewable energy credits under existing

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contractual obligations as of June 1, 2021;
(i-5) funding for the Illinois Solar for All
Program, as described in subparagraph (O) of this
paragraph (1);
(ii) renewable energy credits necessary to comply
with the new wind and new photovoltaic procurement
requirements described in items (i) through (iii) of
subparagraph (C) of this paragraph (1); and
(iii) renewable energy credits necessary to meet
the remaining requirements of this subsection (c).
(G) The following provisions shall apply to the
Agency's procurement of renewable energy credits under
this subsection (c):
(i) Notwithstanding whether a long-term renewable
resources procurement plan has been approved, the
Agency shall conduct an initial forward procurement
for renewable energy credits from new utility-scale
wind projects within 160 days after June 1, 2017 (the
effective date of Public Act 99-906). For the purposes
of this initial forward procurement, the Agency shall
solicit 15-year contracts for delivery of 1,000,000
renewable energy credits delivered annually from new
utility-scale wind projects to begin delivery on June
1, 2019, if available, but not later than June 1, 2021,
unless the project has delays in the establishment of
an operating interconnection with the applicable

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

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actions or inactions of the transmission or
distribution provider, or other causes for force
majeure as outlined in the procurement contract, in
which case, not later than June 1, 2022. The Agency may
structure this initial procurement in one or more
discrete procurement events. Payments to suppliers of
renewable energy credits shall commence upon delivery.
Renewable energy credits procured under this initial
procurement shall be included in the Agency's
long-term plan and shall apply to all renewable energy
goals in this subsection (c).
(iii) Notwithstanding whether the Commission has
approved the periodic long-term renewable resources
procurement plan revision described in Section
16-111.5 of the Public Utilities Act, the Agency shall
conduct at least one subsequent forward procurement
for renewable energy credits from new utility-scale
wind projects, new utility-scale solar projects, and
new brownfield site photovoltaic projects within 240
days after the effective date of this amendatory Act
of the 102nd General Assembly in quantities necessary
to meet the requirements of subparagraph (C) of this
paragraph (1) through the delivery year beginning June
1, 2021.
(iv) Notwithstanding whether the Commission has
approved the periodic long-term renewable resources

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procurement plan revision described in Section
16-111.5 of the Public Utilities Act, the Agency shall
open capacity for each category in the Adjustable
Block program within 90 days after the effective date
of this amendatory Act of the 102nd General Assembly
manner:
(1) The Agency shall open the first block of
annual capacity for the category described in item
(i) of subparagraph (K) of this paragraph (1). The
first block of annual capacity for item (i) shall
be for at least 75 megawatts of total nameplate
capacity. The price of the renewable energy credit
for this block of capacity shall be 4% less than
the price of the last open block in this category.
Projects on a waitlist shall be awarded contracts
first in the order in which they appear on the
waitlist. Notwithstanding anything to the
contrary, for those renewable energy credits that
qualify and are procured under this subitem (1) of
this item (iv), the renewable energy credit
delivery contract value shall be paid in full,
based on the estimated generation during the first
15 years of operation, by the contracting
utilities at the time that the facility producing
the renewable energy credits is interconnected at
the distribution system level of the utility and

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verified as energized and in compliance by the
Program Administrator. The electric utility shall
receive and retire all renewable energy credits
generated by the project for the first 15 years of
operation. Renewable energy credits generated by
the project thereafter shall not be transferred
under the renewable energy credit delivery
contract with the counterparty electric utility.
(2) The Agency shall open the first block of
annual capacity for the category described in item
(ii) of subparagraph (K) of this paragraph (1).
The first block of annual capacity for item (ii)
shall be for at least 75 megawatts of total
nameplate capacity.
(A) The price of the renewable energy
credit for any project on a waitlist for this
category before the opening of this block
shall be 4% less than the price of the last
open block in this category. Projects on the
waitlist shall be awarded contracts first in
the order in which they appear on the
waitlist. Any projects that are less than or
equal to 25 kilowatts in size on the waitlist
for this capacity shall be moved to the
waitlist for paragraph (1) of this item (iv).
Notwithstanding anything to the contrary,

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projects that were on the waitlist prior to
opening of this block shall not be required to
be in compliance with the requirements of
subparagraph (Q) of this paragraph (1) of this
subsection (c). Notwithstanding anything to
the contrary, for those renewable energy
credits procured from projects that were on
the waitlist for this category before the
opening of this block 20% of the renewable
energy credit delivery contract value, based
on the estimated generation during the first
15 years of operation, shall be paid by the
contracting utilities at the time that the
facility producing the renewable energy
credits is interconnected at the distribution
system level of the utility and verified as
energized by the Program Administrator. The
remaining portion shall be paid ratably over
the subsequent 4-year period. The electric
utility shall receive and retire all renewable
energy credits generated by the project during
the first 15 years of operation. Renewable
energy credits generated by the project
thereafter shall not be transferred under the
renewable energy credit delivery contract with
the counterparty electric utility.

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(B) The price of renewable energy credits
for any project not on the waitlist for this
category before the opening of the block shall
be determined and published by the Agency.
Projects not on a waitlist as of the opening
of this block shall be subject to the
requirements of subparagraph (Q) of this
paragraph (1), as applicable. Projects not on
a waitlist as of the opening of this block
shall be subject to the contract provisions
outlined in item (iii) of subparagraph (L) of
this paragraph (1). The Agency shall strive to
publish updated prices and an updated
renewable energy credit delivery contract as
quickly as possible.
(3) For opening the first 2 blocks of annual
capacity for projects participating in item (iii)
of subparagraph (K) of paragraph (1) of subsection
(c), projects shall be selected exclusively from
those projects on the ordinal waitlists of
community renewable generation projects
established by the Agency based on the status of
those ordinal waitlists as of December 31, 2020,
and only those projects previously determined to
be eligible for the Agency's April 2019 community
solar project selection process.

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The first 2 blocks of annual capacity for item
(iii) shall be for 250 megawatts of total
nameplate capacity, with both blocks opening
simultaneously under the schedule outlined in the
paragraphs below. Projects shall be selected as
follows:
(A) The geographic balance of selected
projects shall follow the Group classification
found in the Agency's Revised Long-Term
Renewable Resources Procurement Plan, with 70%
of capacity allocated to projects on the Group
B waitlist and 30% of capacity allocated to
projects on the Group A waitlist.
(B) Contract awards for waitlisted
projects shall be allocated proportionate to
the total nameplate capacity amount across
both ordinal waitlists associated with that
applicant firm or its affiliates, subject to
the following conditions.
(i) Each applicant firm having a
waitlisted project eligible for selection
shall receive no less than 500 kilowatts
in awarded capacity across all groups, and
no approved vendor may receive more than
20% of each Group's waitlist allocation.
(ii) Each applicant firm, upon

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receiving an award of program capacity
proportionate to its waitlisted capacity,
may then determine which waitlisted
projects it chooses to be selected for a
contract award up to that capacity amount.
(iii) Assuming all other program
requirements are met, applicant firms may
adjust the nameplate capacity of applicant
projects without losing waitlist
eligibility, so long as no project is
greater than 2,000 kilowatts in size.
(iv) Assuming all other program
requirements are met, applicant firms may
adjust the expected production associated
with applicant projects, subject to
verification by the Program Administrator.
(C) After a review of affiliate
information and the current ordinal waitlists,
the Agency shall announce the nameplate
capacity award amounts associated with
applicant firms no later than 90 days after
the effective date of this amendatory Act of
the 102nd General Assembly.
(D) Applicant firms shall submit their
portfolio of projects used to satisfy those
contract awards no less than 90 days after the

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Agency's announcement. The total nameplate
capacity of all projects used to satisfy that
portfolio shall be no greater than the
Agency's nameplate capacity award amount
associated with that applicant firm. An
applicant firm may decline, in whole or in
part, its nameplate capacity award without
penalty, with such unmet capacity rolled over
to the next block opening for project
selection under item (iii) of subparagraph (K)
of this subsection (c). Any projects not
included in an applicant firm's portfolio may
reapply without prejudice upon the next block
reopening for project selection under item
(iii) of subparagraph (K) of this subsection
(c).
(E) The renewable energy credit delivery
contract shall be subject to the contract and
payment terms outlined in item (iv) of
subparagraph (L) of this subsection (c).
Contract instruments used for this
subparagraph shall contain the following
terms:
(i) Renewable energy credit prices
shall be fixed, without further adjustment
under any other provision of this Act or

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for any other reason, at 10% lower than
prices applicable to the last open block
for this category, inclusive of any adders
available for achieving a minimum of 50%
of subscribers to the project's nameplate
capacity being residential or small
commercial customers with subscriptions of
below 25 kilowatts in size;
(ii) A requirement that a minimum of
50% of subscribers to the project's
nameplate capacity be residential or small
commercial customers with subscriptions of
below 25 kilowatts in size;
(iii) Permission for the ability of a
contract holder to substitute projects
with other waitlisted projects without
penalty should a project receive a
non-binding estimate of costs to construct
the interconnection facilities and any
required distribution upgrades associated
with that project of greater than 30 cents
per watt AC of that project's nameplate
capacity. In developing the applicable
contract instrument, the Agency may
consider whether other circumstances
outside of the control of the applicant

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firm should also warrant project
substitution rights.
The Agency shall publish a finalized
updated renewable energy credit delivery
contract developed consistent with these terms
and conditions no less than 30 days before
applicant firms must submit their portfolio of
projects pursuant to item (D).
(F) To be eligible for an award, the
applicant firm shall certify that not less
than prevailing wage, as determined pursuant
to the Illinois Prevailing Wage Act, was or
will be paid to employees who are engaged in
construction activities associated with a
selected project.
(4) The Agency shall open the first block of
annual capacity for the category described in item
(iv) of subparagraph (K) of this paragraph (1).
The first block of annual capacity for item (iv)
shall be for at least 50 megawatts of total
nameplate capacity. Renewable energy credit prices
shall be fixed, without further adjustment under
any other provision of this Act or for any other
reason, at the price in the last open block in the
category described in item (ii) of subparagraph
(K) of this paragraph (1). Pricing for future

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blocks of annual capacity for this category may be
adjusted in the Agency's second revision to its
Long-Term Renewable Resources Procurement Plan.
Projects in this category shall be subject to the
contract terms outlined in item (iv) of
subparagraph (L) of this paragraph (1).
(5) The Agency shall open the equivalent of 2
years of annual capacity for the category
described in item (v) of subparagraph (K) of this
paragraph (1). The first block of annual capacity
for item (v) shall be for at least 10 megawatts of
total nameplate capacity. Notwithstanding the
provisions of item (v) of subparagraph (K) of this
paragraph (1), for the purpose of this initial
block, the agency shall accept new project
applications intended to increase the diversity of
areas hosting community solar projects, the
business models of projects, and the size of
projects, as described by the Agency in its
long-term renewable resources procurement plan
that is approved as of the effective date of this
amendatory Act of the 102nd General Assembly.
Projects in this category shall be subject to the
contract terms outlined in item (iii) of
subsection (L) of this paragraph (1).
(6) The Agency shall open the first blocks of

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annual capacity for the category described in item
(vi) of subparagraph (K) of this paragraph (1),
with allocations of capacity within the block
generally matching the historical share of block
capacity allocated between the category described
in items (i) and (ii) of subparagraph (K) of this
paragraph (1). The first two blocks of annual
capacity for item (vi) shall be for at least 75
megawatts of total nameplate capacity. The price
of renewable energy credits for the blocks of
capacity shall be 4% less than the price of the
last open blocks in the categories described in
items (i) and (ii) of subparagraph (K) of this
paragraph (1). Pricing for future blocks of annual
capacity for this category may be adjusted in the
Agency's second revision to its Long-Term
Renewable Resources Procurement Plan. Projects in
this category shall be subject to the applicable
contract terms outlined in items (ii) and (iii) of
subparagraph (L) of this paragraph (1).
(v) Upon the effective date of this amendatory Act
of the 102nd General Assembly, for all competitive
procurements and any procurements of renewable energy
credit from new utility-scale wind and new
utility-scale photovoltaic projects, the Agency shall
procure indexed renewable energy credits and direct

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respondents to offer a strike price.
(1) The purchase price of the indexed
renewable energy credit payment shall be
calculated for each settlement period. That
payment, for any settlement period, shall be equal
to the difference resulting from subtracting the
strike price from the index price for that
settlement period. If this difference results in a
negative number, the indexed REC counterparty
shall owe the seller the absolute value multiplied
by the quantity of energy produced in the relevant
settlement period. If this difference results in a
positive number, the seller shall owe the indexed
REC counterparty this amount multiplied by the
quantity of energy produced in the relevant
settlement period.
(2) Parties shall cash settle every month,
summing up all settlements (both positive and
negative, if applicable) for the prior month.
(3) To ensure funding in the annual budget
established under subparagraph (E) for indexed
renewable energy credit procurements for each year
of the term of such contracts, which must have a
minimum tenure of 20 calendar years, the
procurement administrator, Agency, Commission
staff, and procurement monitor shall quantify the

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annual cost of the contract by utilizing one or
more industry-standard, third-party forward price
curves for energy at the appropriate hub or load
zone, including the estimated magnitude and timing
of the price effects related to federal carbon
controls. Each forward price curve shall contain a
specific value of the forecasted market price of
electricity for each annual delivery year of the
contract. For procurement planning purposes, the
impact on the annual budget for the cost of
indexed renewable energy credits for each delivery
year shall be determined as the expected annual
contract expenditure for that year, equaling the
difference between (i) the sum across all relevant
contracts of the applicable strike price
multiplied by contract quantity and (ii) the sum
across all relevant contracts of the forward price
curve for the applicable load zone for that year
multiplied by contract quantity. The contracting
utility shall not assume an obligation in excess
of the estimated annual cost of the contracts for
indexed renewable energy credits. Forward curves
shall be revised on an annual basis as updated
forward price curves are released and filed with
the Commission in the proceeding approving the
Agency's most recent long-term renewable resources

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procurement plan. If the expected contract spend
is higher or lower than the total quantity of
contracts multiplied by the forward price curve
value for that year, the forward price curve shall
be updated by the procurement administrator, in
consultation with the Agency, Commission staff,
and procurement monitors, using then-currently
available price forecast data and additional
budget dollars shall be obligated or reobligated
as appropriate.
(4) To ensure that indexed renewable energy
credit prices remain predictable and affordable,
the Agency may consider the institution of a price
collar on REC prices paid under indexed renewable
energy credit procurements establishing floor and
ceiling REC prices applicable to indexed REC
contract prices. Any price collars applicable to
indexed REC procurements shall be proposed by the
Agency through its long-term renewable resources
procurement plan.
(vi) All procurements under this subparagraph (G),
including the procurement of renewable energy credits
from hydropower facilities, shall comply with the
geographic requirements in subparagraph (I) of this
paragraph (1) and shall follow the procurement
processes and procedures described in this Section and

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Section 16-111.5 of the Public Utilities Act to the
extent practicable, and these processes and procedures
may be expedited to accommodate the schedule
established by this subparagraph (G). To ensure the
successful development of new renewable energy
projects supported through competitive procurements,
for any procurements conducted under items (i), (ii),
(iii), and (v) of this subparagraph (G) and any other
procurement of new utility-scale wind or utility-scale
solar projects that were entered into prior to January
1, 2025, the Agency shall allow, upon a demonstration
of need to ensure the commercial viability of a
project, for a one-time, post-award renegotiation of
select contract terms prior to the project's
commercial operation date through bilateral
negotiation between the Agency, the buyer, and a
winning bidder. Contract terms subject to
renegotiation may include the project map, as defined
under the applicable competitive solicitation, the
real estate footprint or any limitations thereof, the
location of the generators, or a potential reduction
in the quantity of renewable energy credits to be
delivered. Provisions related to a renewable energy
credit delivery shortfall and the event of default may
be replaced with similar provisions approved by the
Agency in subsequent years or subsequent to a

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successful bid. Post-award renegotiation of
competitively bid renewable energy credit contracts
entered into prior to January 1, 2025 shall not be
permitted to the extent such renegotiation would
result in (1) the point of interconnection being
within the service area of a different state, a
different regional transmission organization zone, or
a different regional transmission organization, (2)
the generator no longer meeting the definition of the
resource category for which the winning bidder was
originally awarded a contract, (3) the generator no
longer meeting the Agency's public interest criteria
as established in the long-term renewable resources
plan in effect at the time of the contract award, or
(4) a change to material terms of the renewable energy
credit contract unrelated to project land or footprint
or the number of renewable energy credits to be
delivered, including the applicable bid price or
strike price. If the Agency, the buyer, and the
winning bidder reach an agreement on amended terms,
then, upon petition by the winning bidder or current
seller, the Commission shall issue an order directing
the utility counterparty to execute an amendment
drafted by the Agency with the revised terms to the
renewable energy credit contract, the product order,
or both. The Agency shall provide the amendment to the

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utility within 15 business days after the Commission's
order, and the utility shall execute the amendment no
more than 7 calendar days after delivery by the
Agency.
(vii) On and after the effective date of this
amendatory Act of the 103rd General Assembly, for all
procurements of renewable energy credits from
hydropower facilities, the Agency shall establish
contract terms designed to optimize existing
hydropower facilities through modernization or
retooling and establish new hydropower facilities at
existing dams. Procurements made under this item (vii)
shall prioritize projects located in designated
environmental justice communities, as defined in
subsection (b) of Section 1-56 of this Act, or in
projects located in units of local government with
median incomes that do not exceed 82% of the median
income of the State.
(H) The procurement of renewable energy resources for
a given delivery year shall be reduced as described in
this subparagraph (H) if an alternative retail electric
supplier meets the requirements described in this
subparagraph (H).
(i) Within 45 days after June 1, 2017 (the
effective date of Public Act 99-906), an alternative
retail electric supplier or its successor shall submit

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an informational filing to the Illinois Commerce
Commission certifying that, as of December 31, 2015,
the alternative retail electric supplier owned one or
more electric generating facilities that generates
renewable energy resources as defined in Section 1-10
of this Act, provided that such facilities are not
powered by wind or photovoltaics, and the facilities
generate one renewable energy credit for each
megawatthour of energy produced from the facility.
The informational filing shall identify each
facility that was eligible to satisfy the alternative
retail electric supplier's obligations under Section
16-115D of the Public Utilities Act as described in
this item (i).
(ii) For a given delivery year, the alternative
retail electric supplier may elect to supply its
retail customers with renewable energy credits from
the facility or facilities described in item (i) of
this subparagraph (H) that continue to be owned by the
alternative retail electric supplier.
(iii) The alternative retail electric supplier
shall notify the Agency and the applicable utility, no
later than February 28 of the year preceding the
applicable delivery year or 15 days after June 1, 2017
(the effective date of Public Act 99-906), whichever
is later, of its election under item (ii) of this

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subparagraph (H) to supply renewable energy credits to
retail customers of the utility. Such election shall
identify the amount of renewable energy credits to be
supplied by the alternative retail electric supplier
to the utility's retail customers and the source of
the renewable energy credits identified in the
informational filing as described in item (i) of this
subparagraph (H), subject to the following
limitations:
For the delivery year beginning June 1, 2018,
the maximum amount of renewable energy credits to
be supplied by an alternative retail electric
supplier under this subparagraph (H) shall be 68%
multiplied by 25% multiplied by 14.5% multiplied
by the amount of metered electricity
(megawatt-hours) delivered by the alternative
retail electric supplier to Illinois retail
customers during the delivery year ending May 31,
2016.
For delivery years beginning June 1, 2019 and
each year thereafter, the maximum amount of
renewable energy credits to be supplied by an
alternative retail electric supplier under this
subparagraph (H) shall be 68% multiplied by 50%
multiplied by 16% multiplied by the amount of
metered electricity (megawatt-hours) delivered by

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the alternative retail electric supplier to
Illinois retail customers during the delivery year
ending May 31, 2016, provided that the 16% value
shall increase by 1.5% each delivery year
thereafter to 25% by the delivery year beginning
June 1, 2025, and thereafter the 25% value shall
apply to each delivery year.
For each delivery year, the total amount of
renewable energy credits supplied by all alternative
retail electric suppliers under this subparagraph (H)
shall not exceed 9% of the Illinois target renewable
energy credit quantity. The Illinois target renewable
energy credit quantity for the delivery year beginning
June 1, 2018 is 14.5% multiplied by the total amount of
metered electricity (megawatt-hours) delivered in the
delivery year immediately preceding that delivery
year, provided that the 14.5% shall increase by 1.5%
each delivery year thereafter to 25% by the delivery
year beginning June 1, 2025, and thereafter the 25%
value shall apply to each delivery year.
If the requirements set forth in items (i) through
(iii) of this subparagraph (H) are met, the charges
that would otherwise be applicable to the retail
customers of the alternative retail electric supplier
under paragraph (6) of this subsection (c) for the
applicable delivery year shall be reduced by the ratio

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of the quantity of renewable energy credits supplied
by the alternative retail electric supplier compared
to that supplier's target renewable energy credit
quantity. The supplier's target renewable energy
credit quantity for the delivery year beginning June
1, 2018 is 14.5% multiplied by the total amount of
metered electricity (megawatt-hours) delivered by the
alternative retail supplier in that delivery year,
provided that the 14.5% shall increase by 1.5% each
delivery year thereafter to 25% by the delivery year
beginning June 1, 2025, and thereafter the 25% value
shall apply to each delivery year.
On or before April 1 of each year, the Agency shall
annually publish a report on its website that
identifies the aggregate amount of renewable energy
credits supplied by alternative retail electric
suppliers under this subparagraph (H).
(I) The Agency shall design its long-term renewable
energy procurement plan to maximize the State's interest
in the health, safety, and welfare of its residents,
including but not limited to minimizing sulfur dioxide,
nitrogen oxide, particulate matter and other pollution
that adversely affects public health in this State,
increasing fuel and resource diversity in this State,
enhancing the reliability and resiliency of the
electricity distribution system in this State, meeting

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goals to limit carbon dioxide emissions under federal or
State law, and contributing to a cleaner and healthier
environment for the citizens of this State. In order to
further these legislative purposes, renewable energy
credits shall be eligible to be counted toward the
renewable energy requirements of this subsection (c) if
they are generated from facilities located in this State.
The Agency may qualify renewable energy credits from
facilities located in states adjacent to Illinois or
renewable energy credits associated with the electricity
generated by a utility-scale wind energy facility or
utility-scale photovoltaic facility and transmitted by a
qualifying direct current project described in subsection
(b-5) of Section 8-406 of the Public Utilities Act to a
delivery point on the electric transmission grid located
in this State or a state adjacent to Illinois, if the
generator demonstrates and the Agency determines that the
operation of such facility or facilities will help promote
the State's interest in the health, safety, and welfare of
its residents based on the public interest criteria
described above. For the purposes of this Section,
renewable resources that are delivered via a high voltage
direct current converter station located in Illinois shall
be deemed generated in Illinois at the time and location
the energy is converted to alternating current by the high
voltage direct current converter station if the high

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voltage direct current transmission line: (i) after the
effective date of this amendatory Act of the 102nd General
Assembly, was constructed with a project labor agreement;
(ii) is capable of transmitting electricity at 525kv;
(iii) has an Illinois converter station located and
interconnected in the region of the PJM Interconnection,
LLC; (iv) does not operate as a public utility; and (v) if
the high voltage direct current transmission line was
energized after June 1, 2023. To ensure that the public
interest criteria are applied to the procurement and given
full effect, the Agency's long-term procurement plan shall
describe in detail how each public interest factor shall
be considered and weighted for facilities located in
states adjacent to Illinois.
(J) In order to promote the competitive development of
renewable energy resources in furtherance of the State's
interest in the health, safety, and welfare of its
residents, renewable energy credits shall not be eligible
to be counted toward the renewable energy requirements of
this subsection (c) if they are sourced from a generating
unit whose costs were being recovered through rates
regulated by this State or any other state or states on or
after January 1, 2017. Each contract executed to purchase
renewable energy credits under this subsection (c) shall
provide for the contract's termination if the costs of the
generating unit supplying the renewable energy credits

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subsequently begin to be recovered through rates regulated
by this State or any other state or states; and each
contract shall further provide that, in that event, the
supplier of the credits must return 110% of all payments
received under the contract. Amounts returned under the
requirements of this subparagraph (J) shall be retained by
the utility and all of these amounts shall be used for the
procurement of additional renewable energy credits from
new wind or new photovoltaic resources as defined in this
subsection (c). The long-term plan shall provide that
these renewable energy credits shall be procured in the
next procurement event.
Notwithstanding the limitations of this subparagraph
(J), renewable energy credits sourced from generating
units that are constructed, purchased, owned, or leased by
an electric utility as part of an approved project,
program, or pilot under Section 1-56 of this Act shall be
eligible to be counted toward the renewable energy
requirements of this subsection (c), regardless of how the
costs of these units are recovered. As long as a
generating unit or an identifiable portion of a generating
unit has not had and does not have its costs recovered
through rates regulated by this State or any other state,
HVDC renewable energy credits associated with that
generating unit or identifiable portion thereof shall be
eligible to be counted toward the renewable energy

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requirements of this subsection (c).
(K) The long-term renewable resources procurement plan
developed by the Agency in accordance with subparagraph
(A) of this paragraph (1) shall include an Adjustable
Block program for the procurement of renewable energy
credits from new photovoltaic projects that are
distributed renewable energy generation devices or new
photovoltaic community renewable generation projects. The
Adjustable Block program shall be generally designed to
provide for the steady, predictable, and sustainable
growth of new solar photovoltaic development in Illinois.
To this end, the Adjustable Block program shall provide a
transparent annual schedule of prices and quantities to
enable the photovoltaic market to scale up and for
renewable energy credit prices to adjust at a predictable
rate over time. The prices set by the Adjustable Block
program can be reflected as a set value or as the product
of a formula.
The Adjustable Block program shall include for each
category of eligible projects for each delivery year: a
single block of nameplate capacity, a price for renewable
energy credits within that block, and the terms and
conditions for securing a spot on a waitlist once the
block is fully committed or reserved. Except as outlined
below, the waitlist of projects in a given year will carry
over to apply to the subsequent year when another block is

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opened. Only projects energized on or after June 1, 2017
shall be eligible for the Adjustable Block program. For
each category for each delivery year the Agency shall
determine the amount of generation capacity in each block,
and the purchase price for each block, provided that the
purchase price provided and the total amount of generation
in all blocks for all categories shall be sufficient to
meet the goals in this subsection (c). The Agency shall
strive to issue a single block sized to provide for
stability and market growth. The Agency shall establish
program eligibility requirements that ensure that projects
that enter the program are sufficiently mature to indicate
a demonstrable path to completion. The Agency may
periodically review its prior decisions establishing the
amount of generation capacity in each block, and the
purchase price for each block, and may propose, on an
expedited basis, changes to these previously set values,
including but not limited to redistributing these amounts
and the available funds as necessary and appropriate,
subject to Commission approval as part of the periodic
plan revision process described in Section 16-111.5 of the
Public Utilities Act. The Agency may define different
block sizes, purchase prices, or other distinct terms and
conditions for projects located in different utility
service territories if the Agency deems it necessary to
meet the goals in this subsection (c).

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The Adjustable Block program shall include the
following categories in at least the following amounts:
(i) At least 20% from distributed renewable energy
generation devices with a nameplate capacity of no
more than 25 kilowatts.
(ii) At least 20% from distributed renewable
energy generation devices with a nameplate capacity of
more than 25 kilowatts and no more than 5,000
kilowatts. The Agency may create sub-categories within
this category to account for the differences between
projects for small commercial customers, large
commercial customers, and public or non-profit
customers. A project shall not be colocated with one
or more other distributed renewable energy generation
projects if the aggregate nameplate capacity of the
projects exceeds 5,000 kilowatts AC. Notwithstanding
any other provision of this Section, if 2 or more
projects are developed, owned, or controlled by or
originate from the same developer or an affiliated
developer and the projects serve affiliated loads, the
projects shall be colocated if the projects are
located on adjacent parcels. If 2 or more projects are
developed, owned, or controlled by or originate from
the same developer and the projects serve unaffiliated
loads, the projects may be colocated if documentation
indicates affiliated management and ownership in the

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pre-development, development, construction, and
management of the projects and the projects are
located on a single or adjacent parcels.
Notwithstanding any subsequent transfer, assignment,
or conveyance of ownership or development rights to
separate legal entities, the Agency shall consider, in
its determination of whether projects are affiliated,
evidence that the projects were pre-developed by the
same legal entity or an affiliated entity. If the
Agency determines the projects are affiliated, the
projects shall be treated as colocated for purposes of
aggregate nameplate capacity limitations and renewable
energy credit pricing adjustments. The Agency shall
make exceptions on a case-by-case basis if it is
demonstrated that projects on one parcel or projects
on adjacent parcels are unaffiliated. For purposes of
determining colocation, an approved vendor who submits
an application for a distributed renewable energy
generation project shall be required to submit an
affidavit attesting that the project is not affiliated
with any other distributed renewable energy generation
project such that, if the 2 projects were deemed
colocated, the projects would exceed the 5,000
kilowatts nameplate capacity limitation. The receipt
of an affidavit shall not restrict the Agency's
ability to investigate and determine whether the

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project is, in fact, colocated.
For purposes of this item (ii):
"Affiliate" has the meaning given to that term in
subitem (3) of item (iii) of this subparagraph (K).
"Colocated" means 2 or more distributed renewable
energy generation projects that are located on a
single parcel, except for projects where the owner of
the applicable retail electric account is confirmed to
be unaffiliated and the projects serve distinct
electrical loads.
"Control" has the meaning given to that term in
subitem (3) of item (iii) of this subparagraph (K).
(iii) At least 30% from photovoltaic community
renewable generation projects. Capacity for this
category for the first 2 delivery years after the
effective date of this amendatory Act of the 102nd
General Assembly shall be allocated to waitlist
projects as provided in paragraph (3) of item (iv) of
subparagraph (G). Starting in the third delivery year
after the effective date of this amendatory Act of the
102nd General Assembly or earlier if the Agency
determines there is additional capacity needed for to
meet previous delivery year requirements, the
following shall apply:
(1) the Agency shall select projects on a
first-come, first-serve basis, however the Agency

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may suggest additional methods to prioritize
projects that are submitted at the same time;
(2) projects shall have subscriptions of 25 kW
or less for at least 50% of the facility's
nameplate capacity and the Agency shall price the
renewable energy credits with that as a factor;
(3) projects shall not be colocated with one
or more other photovoltaic community renewable
generation projects such that the aggregate
nameplate capacity exceeds 10,000 kilowatts. The
total nameplate capacity of colocated projects
shall be the sum of the nameplate capacities of
the individual projects. For purposes of this
subitem (3), separate legal formation of approved
vendors, owners, or developers shall not preclude
a finding of affiliation by the Agency. Evidence
of affiliation may include, but is not limited to,
shared personnel, common contractual or financing
arrangements, a shared interconnection agreement,
distinct interconnection agreements obtained by
the same pre-development entity that are
subsequently sold to distinct legal entities,
familial relationships, or any demonstrable
pattern of coordinated action in the
pre-development, development, construction, or
management of photovoltaic community renewable

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generation projects.
The Agency shall determine affiliation based
on evidence that projects either (i) share a
common origin on a parcel that has been subdivided
in the 5 years before the date of application or
(ii) were pre-developed before the beginning of
construction by the same legal entity or an
affiliated legal entity. The determination shall
be made notwithstanding any subsequent transfer,
assignment, or conveyance of ownership or
development rights to separate legal entities. If
the Agency determines the projects are affiliated,
the projects shall be treated as colocated for the
purposes of aggregate nameplate capacity
limitations and renewable energy credit pricing
adjustments. The Agency shall make exceptions to
this subitem (3) on a case-by-case basis if it is
demonstrated that projects on one parcel or
projects on adjacent parcels are unaffiliated.
A parcel shall not be divided into multiple
parcels within the 5 years before the submission
of a project application. If a parcel is divided
within the preceding 5 years, a colocation
determination shall be made based on the
boundaries of the previous undivided parcel.
For purposes of determining colocation, an

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approved vendor who submits an application for a
photovoltaic community renewable generation
project shall be required to submit an affidavit
attesting that (i) the parcel on which the project
is sited has not been subdivided within the 5
years preceding the project application and (ii)
the project is not affiliated with any other
photovoltaic community renewable generation energy
project in a manner that would cause the 2
projects, if deemed colocated, to exceed the
10,000 kilowatt nameplate capacity limitation. The
receipt of an affidavit shall not restrict the
Agency's ability to investigate and determine
whether the project is colocated.
Multiple photovoltaic community renewable
generation community solar projects sited on
distinct structures located on a single parcel
shall be considered colocated and must demonstrate
that the projects are unaffiliated in order to not
be considered colocated. Each colocated project
shall receive the renewable energy credit price
corresponding to the total, aggregated nameplate
capacity of the colocated systems, as determined
at the time the second project's application is
submitted to the Agency. If the second colocated
project has been constructed and placed in service

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prior to application, and was placed in service
more than 2 years after Commission approval of the
original project, the colocation pricing
adjustment shall not apply, and each project shall
receive the standalone renewable energy credit
price for its individual capacity.
For purposes of this subitem (3):
"Affiliate" means any other entity that,
directly or indirectly through one or more
intermediaries, is controlled by or is under
common control of the primary entity or a third
entity. "Affiliate" includes family members for
the purposes of colocation between projects.
"Affiliate" does not include entities that have
shared sales or revenue-sharing arrangements or
common debt and equity financing arrangements.
"Colocated" means 2 or more photovoltaic
community renewable generation projects located on
a single parcel or adjacent parcels, unless it is
demonstrated that the projects are developed by
unaffiliated entities.
"Control" means the possession, directly or
indirectly, of the power to direct the management
and policies of an entity; and
(4) projects greater than 2 MW may not apply
until after the approval of the Agency's revised

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Long-Term Renewable Resources Procurement Plan
after the effective date of this amendatory Act of
the 102nd General Assembly.
(iv) At least 15% from distributed renewable
generation devices or photovoltaic community renewable
generation projects installed on public school land.
The Agency may create subcategories within this
category to account for the differences between
project size or location. Projects located within
environmental justice communities or within
Organizational Units that fall within Tier 1 or Tier 2
shall be given priority. Each of the Agency's periodic
updates to its long-term renewable resources
procurement plan to incorporate the procurement
described in this subparagraph (iv) shall also include
the proposed quantities or blocks, pricing, and
contract terms applicable to the procurement as
indicated herein. In each such update and procurement,
the Agency shall set the renewable energy credit price
and establish payment terms for the renewable energy
credits procured pursuant to this subparagraph (iv)
that make it feasible and affordable for public
schools to install photovoltaic distributed renewable
energy devices on their premises, including, but not
limited to, those public schools subject to the
prioritization provisions of this subparagraph. For

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the purposes of this item (iv):
"Environmental Justice Community" shall have the
same meaning set forth in the Agency's long-term
renewable resources procurement plan;
"Organization Unit", "Tier 1" and "Tier 2" shall
have the meanings set for in Section 18-8.15 of the
School Code;
"Public schools" shall have the meaning set forth
in Section 1-3 of the School Code and includes public
institutions of higher education, as defined in the
Board of Higher Education Act.
(v) At least 5% from community-driven community
solar projects intended to provide more direct and
tangible connection and benefits to the communities
which they serve or in which they operate and,
additionally, to increase the variety of community
solar locations, models, and options in Illinois. As
part of its long-term renewable resources procurement
plan, the Agency shall develop selection criteria for
projects participating in this category. Nothing in
this Section shall preclude the Agency from creating a
selection process that maximizes community ownership
and community benefits in selecting projects to
receive renewable energy credits. Selection criteria
shall include:
(1) community ownership or community

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wealth-building;
(2) additional direct and indirect community
benefit, beyond project participation as a
subscriber, including, but not limited to,
economic, environmental, social, cultural, and
physical benefits;
(3) meaningful involvement in project
organization and development by community members
or nonprofit organizations or public entities
located in or serving the community;
(4) engagement in project operations and
management by nonprofit organizations, public
entities, or community members; and
(5) whether a project is developed in response
to a site-specific RFP developed by community
members or a nonprofit organization or public
entity located in or serving the community.
Selection criteria may also prioritize projects
that:
(1) are developed in collaboration with or to
provide complementary opportunities for the Clean
Jobs Workforce Network Program, the Illinois
Climate Works Preapprenticeship Program, the
Returning Residents Clean Jobs Training Program,
the Clean Energy Contractor Incubator Program, or
the Clean Energy Primes Contractor Accelerator

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Program;
(2) increase the diversity of locations of
community solar projects in Illinois, including by
locating in urban areas and population centers;
(3) are located in Equity Investment Eligible
Communities;
(4) are not greenfield projects;
(5) serve only local subscribers;
(6) have a nameplate capacity that does not
exceed 500 kW;
(7) are developed by an equity eligible
contractor; or
(8) otherwise meaningfully advance the goals
of providing more direct and tangible connection
and benefits to the communities which they serve
or in which they operate and increasing the
variety of community solar locations, models, and
options in Illinois.
For the purposes of this item (v):
"Community" means a social unit in which people
come together regularly to effect change; a social
unit in which participants are marked by a cooperative
spirit, a common purpose, or shared interests or
characteristics; or a space understood by its
residents to be delineated through geographic
boundaries or landmarks.

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"Community benefit" means a range of services and
activities that provide affirmative, economic,
environmental, social, cultural, or physical value to
a community; or a mechanism that enables economic
development, high-quality employment, and education
opportunities for local workers and residents, or
formal monitoring and oversight structures such that
community members may ensure that those services and
activities respond to local knowledge and needs.
"Community ownership" means an arrangement in
which an electric generating facility is, or over time
will be, in significant part, owned collectively by
members of the community to which an electric
generating facility provides benefits; members of that
community participate in decisions regarding the
governance, operation, maintenance, and upgrades of
and to that facility; and members of that community
benefit from regular use of that facility.
Terms and guidance within these criteria that are
not defined in this item (v) shall be defined by the
Agency, with stakeholder input, during the development
of the Agency's long-term renewable resources
procurement plan. The Agency shall develop regular
opportunities for projects to submit applications for
projects under this category, and develop selection
criteria that gives preference to projects that better

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meet individual criteria as well as projects that
address a higher number of criteria.
(vi) At least 10% from distributed renewable
energy generation devices, which includes distributed
renewable energy devices with a nameplate capacity
under 5,000 kilowatts or photovoltaic community
renewable generation projects, from applicants that
are equity eligible contractors. The Agency may create
subcategories within this category to account for the
differences between project size and type. The Agency
shall propose to increase the percentage in this item
(vi) over time to 40% based on factors, including, but
not limited to, the number of equity eligible
contractors and capacity used in this item (vi) in
previous delivery years.
The Agency shall propose a payment structure for
contracts executed pursuant to this paragraph under
which, upon a demonstration of qualification or need
under criteria established by the Agency that is
focused on supporting small and emerging businesses
and businesses that most acutely face barriers to the
access of capital, applicant firms are advanced
capital disbursed after contract execution but before
the contracted project's energization. The amount or
percentage of capital advanced prior to project
energization shall be sufficient to both cover any

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increase in development costs resulting from
prevailing wage requirements or project-labor
agreements, and designed to overcome barriers in
access to capital faced by equity eligible
contractors. The amount or percentage of advanced
capital may vary by subcategory within this category
and by an applicant's demonstration of need, with such
levels to be established through the Long-Term
Renewable Resources Procurement Plan authorized under
subparagraph (A) of paragraph (1) of subsection (c) of
this Section and any application requirements or
evaluation criteria developed pursuant to the Plan.
Contracts developed featuring capital advanced
prior to a project's energization shall feature
provisions to ensure both the successful development
of applicant projects and the delivery of the
renewable energy credits for the full term of the
contract, including ongoing collateral requirements
and other provisions deemed necessary by the Agency,
and may include energization timelines longer than for
comparable project types. The percentage or amount of
capital advanced prior to project energization shall
not operate to increase the overall contract value,
however contracts executed under this subparagraph may
feature renewable energy credit prices higher than
those offered to similar projects participating in

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other categories. Capital advanced prior to
energization shall serve to reduce the ratable
payments made after energization under items (ii) and
(iii) of subparagraph (L) or payments made for each
renewable energy credit delivery under item (iv) of
subparagraph (L).
For projects developed under this item (vi), the
Agency shall take steps to encourage higher portions
of contract value to be provided to equity eligible
contractors and to support equity eligible persons who
participate in this Program and who exercise control
and actively manage their businesses and their
businesses' contractual projects. These steps may
include, but are not limited to, differentiated REC
prices, exceptions or exemptions, and other mechanisms
and requirements for nonnominal contract value to be
provided to equity eligible contractors and equity
eligible persons as a prerequisite to Program
participation. Any steps taken shall aim to encourage
and grow the meaningful participation of equity
eligible contractors in this State's clean energy
economy. All entities participating under this item
(vi) shall comply with the minimum equity standard set
forth under Section 1-75.
(vii) The remaining capacity shall be allocated by
the Agency in order to respond to market demand. The

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Agency shall allocate any discretionary capacity prior
to the beginning of each delivery year.
(viii) The Agency, through its long-term renewable
resources procurement plan, may implement solutions to
maintain stable and consistent REC offerings allocated
to systems described in item (i) of this subparagraph
(K) to avoid gaps in availability during a delivery
year, including, but not limited to, creating a
floating block of REC capacity in a given delivery
year.
To the extent there is uncontracted capacity from any
block in any of categories (i) through (vi) at the end of a
delivery year, the Agency shall redistribute that capacity
to one or more other categories giving priority to
categories with projects on a waitlist. The redistributed
capacity shall be added to the annual capacity in the
subsequent delivery year, and the price for renewable
energy credits shall be the price for the new delivery
year. Redistributed capacity shall not be considered
redistributed when determining whether the goals in this
subsection (K) have been met.
Notwithstanding anything to the contrary, as the
Agency increases the capacity in item (vi) to 40% over
time, the Agency may reduce the capacity of items (i)
through (v) proportionate to the capacity of the
categories of projects in item (vi), to achieve a balance

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of project types.
The Adjustable Block program shall be designed to
ensure that renewable energy credits are procured from
projects in diverse locations and are not concentrated in
a few regional areas.
(L) Notwithstanding provisions for advancing capital
prior to project energization found in item (vi) of
subparagraph (K), the procurement of photovoltaic
renewable energy credits under items (i) through (vi) of
subparagraph (K) of this paragraph (1) shall otherwise be
subject to the following contract and payment terms:
(i) (Blank).
(ii) Unless otherwise provided for in the Agency's
approved long-term plan, for those renewable energy
credits that qualify and are procured under item (i)
of subparagraph (K) of this paragraph (1), and any
similar category projects that are procured under item
(vi) of subparagraph (K) of this paragraph (1) that
qualify and are procured under item (vi), the contract
length shall be 15 years. Beginning on the effective
date of this amendatory Act of the 104th General
Assembly, and including the remainder of program year
2026-2027, 50% of the renewable energy credit delivery
contract value, based on the estimated generation
during the first 15 years of operation, shall be paid
by the contracting utilities at the time that the

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facility producing the renewable energy credits is
interconnected at the distribution system level of the
utility and verified as energized and compliant by the
Program Administrator. The remaining portion of the
renewable energy credit delivery contract value shall
be paid ratably over the subsequent 6-year period.
Relative to a contract structure under which the full
renewable energy credit delivery contract value shall
be paid in full at the time of interconnection and
verification of energization, the Agency shall
consider the impact of deferred payments across the
subsequent payment period when establishing renewable
energy credit prices. The electric utility shall
receive and retire all renewable energy credits
generated by the project for the first 15 years of
operation. Renewable energy credits generated by the
project thereafter shall not be transferred under the
renewable energy credit delivery contract with the
counterparty electric utility.
(iii) Unless otherwise provided for in the
Agency's approved long-term plan, for those renewable
energy credits that qualify and are procured under
item (ii) and (v) of subparagraph (K) of this
paragraph (1) and any like projects that qualify and
are procured under items (iv) and (vi), the contract
length shall be 15 years. 15% of the renewable energy

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credit delivery contract value, based on the estimated
generation during the first 15 years of operation,
shall be paid by the contracting utilities at the time
that the facility producing the renewable energy
credits is interconnected at the distribution system
level of the utility and verified as energized and
compliant by the Program Administrator. The remaining
portion shall be paid ratably over the subsequent
6-year period. The electric utility shall receive and
retire all renewable energy credits generated by the
project for the first 15 years of operation. Renewable
energy credits generated by the project thereafter
shall not be transferred under the renewable energy
credit delivery contract with the counterparty
electric utility.
(iv) Unless otherwise provided for in the Agency's
approved long-term plan, for those renewable energy
credits that qualify and are procured under item (iii)
of subparagraph (K) of this paragraph (1), and any
like projects that qualify and are procured under
items (iv) and (vi), the renewable energy credit
delivery contract length shall be 20 years and shall
be paid over the delivery term, not to exceed during
each delivery year the contract price multiplied by
the estimated annual renewable energy credit
generation amount. If generation of renewable energy

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credits during a delivery year exceeds the estimated
annual generation amount, the excess renewable energy
credits shall be carried forward to future delivery
years and shall not expire during the delivery term.
If generation of renewable energy credits during a
delivery year, including carried forward excess
renewable energy credits, if any, is less than the
estimated annual generation amount, payments during
such delivery year will not exceed the quantity
generated plus the quantity carried forward multiplied
by the contract price. The electric utility shall
receive all renewable energy credits generated by the
project during the first 20 years of operation and
retire all renewable energy credits paid for under
this item (iv) and return at the end of the delivery
term all renewable energy credits that were not paid
for. Renewable energy credits generated by the project
thereafter shall not be transferred under the
renewable energy credit delivery contract with the
counterparty electric utility. Notwithstanding the
preceding, for those projects participating under item
(iii) of subparagraph (K), the contract price for a
delivery year shall be based on subscription levels as
measured on the higher of the first business day of the
delivery year or the first business day 6 months after
the first business day of the delivery year.

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Subscription of 90% of nameplate capacity or greater
shall be deemed to be fully subscribed for the
purposes of this item (iv). For projects receiving a
20-year delivery contract, REC prices shall be
adjusted downward for consistency with the incentive
levels previously determined to be necessary to
support projects under 15-year delivery contracts,
taking into consideration any additional new
requirements placed on the projects, including, but
not limited to, labor standards.
(v) Each contract shall include provisions to
ensure the delivery of the estimated quantity of
renewable energy credits and ongoing collateral
requirements and other provisions deemed appropriate
by the Agency.
(vi) The utility shall be the counterparty to the
contracts executed under this subparagraph (L) that
are approved by the Commission under the process
described in Section 16-111.5 of the Public Utilities
Act. No contract shall be executed for an amount that
is less than one renewable energy credit per year.
(vii) If, at any time, approved applications for
the Adjustable Block program exceed funds collected by
the electric utility or would cause the Agency to
exceed the limitation described in subparagraph (E) of
this paragraph (1) on the amount of renewable energy

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resources that may be procured, then the Agency may
consider future uncommitted funds to be reserved for
these contracts on a first-come, first-served basis.
(viii) Nothing in this Section shall require the
utility to advance any payment or pay any amounts that
exceed the actual amount of revenues anticipated to be
collected by the utility under paragraph (6) of this
subsection (c) and subsection (k) of Section 16-108 of
the Public Utilities Act inclusive of eligible funds
collected in prior years and alternative compliance
payments for use by the utility.
(ix) Notwithstanding other requirements of this
subparagraph (L), no modification shall be required to
Adjustable Block program contracts if they were
already executed prior to the establishment, approval,
and implementation of new contract forms as a result
of this amendatory Act of the 102nd General Assembly.
(x) Contracts may be assignable, but only to
entities first deemed by the Agency to have met
program terms and requirements applicable to direct
program participation. In developing contracts for the
delivery of renewable energy credits, the Agency shall
be permitted to establish fees applicable to each
contract assignment.
(M) The Agency shall be authorized to retain one or
more experts or expert consulting firms to develop,

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administer, implement, operate, and evaluate the
Adjustable Block program described in subparagraph (K) of
this paragraph (1), as well as the Geothermal Homes and
Businesses Program described in subparagraph (S) of this
paragraph (1), and the Agency shall retain the consultant
or consultants in the same manner, to the extent
practicable, as the Agency retains others to administer
provisions of this Act, including, but not limited to, the
procurement administrator. The selection of experts and
expert consulting firms and the procurement process
described in this subparagraph (M) are exempt from the
requirements of Section 20-10 of the Illinois Procurement
Code, under Section 20-10 of that Code. The Agency shall
strive to minimize administrative expenses in the
implementation of the Adjustable Block program.
The Program Administrator may charge application fees
to participating firms to cover the cost of program
administration. Any application fee amounts shall
initially be determined through the long-term renewable
resources procurement plan, and modifications to any
application fee that deviate more than 25% from the
Commission's approved value must be approved by the
Commission as a long-term plan revision under Section
16-111.5 of the Public Utilities Act. The Agency shall
consider stakeholder feedback when making adjustments to
application fees and shall notify stakeholders in advance

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of any planned changes.
In addition to covering the costs of program
administration, the Agency, in conjunction with its
Program Administrator, may also use the proceeds of such
fees charged to participating firms to support public
education and ongoing regional and national coordination
with nonprofit organizations, public bodies, and others
engaged in the implementation of renewable energy
incentive programs or similar initiatives. This work may
include developing papers and reports, hosting regional
and national conferences, and other work deemed necessary
by the Agency to position the State of Illinois as a
national leader in renewable energy incentive program
development and administration.
The Agency and its consultant or consultants shall
monitor block activity, share program activity with
stakeholders and conduct quarterly meetings to discuss
program activity and market conditions. If necessary, the
Agency may make prospective administrative adjustments to
the Adjustable Block program and the Geothermal Homes and
Businesses Program design, such as making adjustments to
purchase prices as necessary to achieve the goals of this
subsection (c). Program modifications to any block price
that do not deviate from the Commission's approved value
by more than 10% shall take effect immediately and are not
subject to Commission review and approval. Program

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modifications to any block price that deviate more than
10% from the Commission's approved value must be approved
by the Commission as a long-term plan amendment under
Section 16-111.5 of the Public Utilities Act. The Agency
shall consider stakeholder feedback when making
adjustments to the Adjustable Block and the Geothermal
Homes and Businesses Program design and shall notify
stakeholders in advance of any planned changes.
The Agency and its program administrators for the
Adjustable Block program, the Illinois Solar for All
Program, and the Geothermal Homes and Businesses Program
consistent with the requirements of this subsection (c)
and subsection (b) of Section 1-56 of this Act, shall
propose the Adjustable Block program terms, conditions,
and requirements, including the prices to be paid for
renewable energy credits, where applicable, and
requirements applicable to participating entities and
project applications, through the development, review, and
approval of the Agency's long-term renewable resources
procurement plan described in this subsection (c) and
paragraph (5) of subsection (b) of Section 16-111.5 of the
Public Utilities Act. Terms, conditions, and requirements
for program participation shall include the following:
(i) The Agency shall establish a registration
process for entities seeking to qualify for
program-administered incentive funding and establish

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baseline qualifications for vendor approval. The
Agency shall also establish program requirements and
minimum contract terms for vendors and others involved
in the marketing, sale, installation, and financing of
distributed generation systems and community solar
subscriptions to prevent misleading marketing and
abusive practices and to otherwise protect customers.
The Agency must maintain a list of approved entities
on each program's website, and may revoke a vendor's
ability to receive program-administered incentive
funding status upon a determination that the vendor
failed to comply with contract terms, the law, or
other program requirements.
(ii) The Agency shall establish program
requirements and minimum contract terms to ensure
projects are properly installed and produce their
expected amounts of energy. Program requirements may
include on-site inspections and photo documentation of
projects under construction. The Agency may require
repairs, alterations, or additions to remedy any
material deficiencies discovered. Vendors who have a
disproportionately high number of deficient systems
may lose their eligibility to continue to receive
State-administered incentive funding through Agency
programs and procurements.
(iii) To discourage deceptive marketing or other

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bad faith business practices, the Agency may require
direct program participants, including agents
operating on their behalf, to provide standardized
disclosures to a customer prior to that customer's
execution of a contract for the development of a
distributed generation system, a subscription to a
community solar project, or the development of a
geothermal heating and cooling system.
(iv) The Agency shall establish one or multiple
Consumer Complaints Centers to accept complaints
regarding businesses that participate in, or otherwise
benefit from, State-administered incentive funding
through Agency-administered programs. The Agency shall
maintain a public database of complaints with any
confidential or particularly sensitive information
redacted from public entries.
(v) Through a filing in the proceeding for the
approval of its long-term renewable energy resources
procurement plan, the Agency shall provide an annual
written report to the Illinois Commerce Commission
documenting the frequency and nature of complaints and
any enforcement actions taken in response to those
complaints.
(vi) The Agency shall schedule regular meetings
with representatives of the Office of the Attorney
General, the Illinois Commerce Commission, consumer

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protection groups, and other interested stakeholders
to share relevant information about consumer
protection, project compliance, and complaints
received.
(vii) To the extent that complaints received
implicate the jurisdiction of the Office of the
Attorney General, the Illinois Commerce Commission, or
local, State, or federal law enforcement, the Agency
shall also refer complaints to those entities as
appropriate.
(viii) The Agency may, at its discretion,
establish a registration process for entities, or a
subset of entities, that provide financing for
consumers for the purchase of distributed renewable
generation devices. The Agency may establish baseline
qualifications for financing entity approval,
including defining the circumstances under which
financing entities may be subject to registration. The
Agency may also establish program requirements for
entities that provide financing for the purchase of
distributed renewable generation devices, which may
include marketing and disclosure requirements, other
requirements as further defined by the Agency through
its long-term plan, and any consumer protection
requirements developed or modified thereto. If the
Agency establishes a registration process for

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financing entities, the Agency may revoke a financing
entity's approval in a program upon a determination
that the financing entity failed to comply with
contract terms, the law, or other program
requirements. The Agency may also establish program
requirements that prohibit distributed renewable
generation devices intending to apply for
program-administered incentive funding from receiving
program funding if the consumer's purchase of the
device was financed by an entity whose approval status
in the program has been revoked. These registration
requirements may apply to entities that finance
projects intended to apply for program-administered
incentive funding even if those entities do not
receive any portion of the program-administered
incentive funding.
(ix) The Agency, at its discretion, may require
that vendors, as part of the application and annual
recertification process, present the Agency or its
designee with a security bond equal to an amount
determined to be reasonable by the Agency. The bond
shall be for the benefit of customers harmed by the
vendor's violation of Agency requirements or other
applicable laws or regulations. The Agency may
determine that it is reasonable to have no bond
requirement for some categories of vendors or enhanced

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bond requirements for vendors that the Agency has
deemed to pose more acute risks.
(x) For distributed renewable generation devices,
the Agency may, in its discretion, establish
provisions that restrict, prohibit, or create
additional requirements for distributed renewable
generation device sales or financing offers through
which the customer is promised the pass-through of a
portion or all of the payments received by the
approved vendor for the delivery of renewable energy
credits only after the receipt of such payment by the
approved vendor. The requirements may include the use
of an escrow process developed by the Agency through
which renewable energy credit payments are made to an
escrow agent who then disburses the promised amount to
the customer and the remainder to the vendor. The
requirements in this item (x) shall in no way prohibit
the upfront discounting of the purchase price, lease
payment, or power purchase agreement rate based on the
anticipated receipt of renewable energy credit
contract payments by the approved vendor.
(xi) To the extent that distributed renewable
generation device sales or financing offers through
which the customer is promised the pass-through of a
portion or all of the payments received by the vendor
for the delivery of renewable energy credits after the

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receipt of such payment by the vendor are permitted,
the following requirements may be implemented, at the
Agency's discretion, in a time and manner determined
by the Agency:
(I) the vendor shall submit proof of customer
payments to the Agency as the Agency deems
necessary; and
(II) the vendor shall represent and warrant on
a form developed by the Agency that the vendor is
not insolvent, has not voluntarily filed for
bankruptcy, and has not been subject to or
threatened with involuntary insolvency.
(xii) To ensure that customers receive full and
uninterrupted benefits and services promised by
vendors, the Agency may propose additional solutions
through its long-term renewable resources procurement
plan described in this subsection (c) and paragraph
(5) of subsection (b) of Section 16-111.5 of the
Public Utilities Act. The solutions may allow for
collections made pursuant to subsection (k) of Section
16-108 of the Public Utilities Act to support the
programs and procurements outlined in paragraph (1) of
subsection (c) of this Section to be leveraged to (1)
ensure that a vendor's promised payments are received
by customers, (2) incentivize vendors to establish
service agreements with customers whose original

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vendor has become nonresponsive, (3) ensure that
customers receive restitution for financial harm
proven to be caused by a program vendor or its
designee, or (4) otherwise ensure that customers do
not suffer loss or harm through activities supported
by the Adjustable Block program and the Illinois Solar
for All Program.
(N) The Agency shall establish the terms, conditions,
and program requirements for photovoltaic community
renewable generation projects with a goal to expand access
to a broader group of energy consumers, to ensure robust
participation opportunities for residential and small
commercial customers and those who cannot install
renewable energy on their own properties. Subject to
reasonable limitations, any plan approved by the
Commission shall allow subscriptions to community
renewable generation projects to be portable and
transferable. For purposes of this subparagraph (N),
"portable" means that subscriptions may be retained by the
subscriber even if the subscriber relocates or changes its
address within the same utility service territory; and
"transferable" means that a subscriber may assign or sell
subscriptions to another person within the same utility
service territory.
Through the development of its long-term renewable
resources procurement plan, the Agency may consider

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whether community renewable generation projects utilizing
technologies other than photovoltaics should be supported
through State-administered incentive funding, and may
issue requests for information to gauge market demand.
Electric utilities shall provide a monetary credit to
a subscriber's subsequent bill for service for the
proportional output of a community renewable generation
project attributable to that subscriber as specified in
Section 16-107.5 of the Public Utilities Act.
The Agency shall purchase renewable energy credits
from subscribed shares of photovoltaic community renewable
generation projects through the Adjustable Block program
described in subparagraph (K) of this paragraph (1) or
through the Illinois Solar for All Program described in
Section 1-56 of this Act. The electric utility shall
purchase any unsubscribed energy from community renewable
generation projects that are Qualifying Facilities ("QF")
under the electric utility's tariff for purchasing the
output from QFs under Public Utilities Regulatory Policies
Act of 1978.
The owners of and any subscribers to a community
renewable generation project shall not be considered
public utilities or alternative retail electricity
suppliers under the Public Utilities Act solely as a
result of their interest in or subscription to a community
renewable generation project and shall not be required to

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become an alternative retail electric supplier by
participating in a community renewable generation project
with a public utility.
(O) For the delivery year beginning June 1, 2018, the
long-term renewable resources procurement plan required by
this subsection (c) shall provide for the Agency to
procure contracts to continue offering the Illinois Solar
for All Program described in subsection (b) of Section
1-56 of this Act, and the contracts approved by the
Commission shall be executed by the utilities that are
subject to this subsection (c). The long-term renewable
resources procurement plan shall allocate up to
$50,000,000 per delivery year to fund the programs, and
the plan shall determine the amount of funding to be
apportioned to the programs identified in subsection (b)
of Section 1-56 of this Act; provided that for the
delivery years beginning June 1, 2021, June 1, 2022, and
June 1, 2023, the long-term renewable resources
procurement plan may average the annual budgets over a
3-year period to account for program ramp-up. For the
delivery years beginning June 1, 2021, June 1, 2024, June
1, 2027, and June 1, 2030 and additional $10,000,000 shall
be provided to the Department of Commerce and Economic
Opportunity to implement the workforce development
programs and reporting as outlined in Section 16-108.12 of
the Public Utilities Act. In making the determinations

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required under this subparagraph (O), the Commission shall
consider the experience and performance under the programs
and any evaluation reports. The Commission shall also
provide for an independent evaluation of those programs on
a periodic basis that are funded under this subparagraph
(O).
(P) All programs and procurements under this
subsection (c) shall be designed to encourage
participating projects to use a diverse and equitable
workforce and a diverse set of contractors, including
minority-owned businesses, disadvantaged businesses,
trade unions, graduates of any workforce training programs
administered under this Act, and small businesses.
The Agency shall develop a method to optimize
procurement of renewable energy credits from proposed
utility-scale projects that are located in communities
eligible to receive Energy Transition Community Grants
pursuant to Section 10-20 of the Energy Community
Reinvestment Act. If this requirement conflicts with other
provisions of law or the Agency determines that full
compliance with the requirements of this subparagraph (P)
would be unreasonably costly or administratively
impractical, the Agency is to propose alternative
approaches to achieve development of renewable energy
resources in communities eligible to receive Energy
Transition Community Grants pursuant to Section 10-20 of

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the Energy Community Reinvestment Act or seek an exemption
from this requirement from the Commission.
(Q) Each facility listed in subitems (i) through (x)
(ix) of item (1) of this subparagraph (Q) for which a
renewable energy credit delivery contract is signed after
the effective date of this amendatory Act of the 102nd
General Assembly is subject to the following requirements
through the Agency's long-term renewable resources
procurement plan:
(1) Each facility shall be subject to the
prevailing wage requirements included in the
Prevailing Wage Act. The Agency shall require
verification that all construction performed on the
facility by the renewable energy credit delivery
contract holder, its contractors, or its
subcontractors relating to construction of the
facility is performed by construction employees
receiving an amount for that work equal to or greater
than the general prevailing rate, as that term is
defined in Section 2 of the Prevailing Wage Act. For
purposes of this item (1), "house of worship" means
property that is both (1) used exclusively by a
religious society or body of persons as a place for
religious exercise or religious worship and (2)
recognized as exempt from taxation pursuant to Section
15-40 of the Property Tax Code. This item (1) shall

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apply to any of the following:
(i) all new utility-scale wind projects;
(ii) all new utility-scale photovoltaic
projects and repowered wind projects;
(iii) all new brownfield photovoltaic
projects;
(iv) all new photovoltaic community renewable
energy facilities that qualify for item (iii) of
subparagraph (K) of this paragraph (1);
(v) all new community driven community
photovoltaic projects that qualify for item (v) of
subparagraph (K) of this paragraph (1);
(vi) all new photovoltaic projects on public
school land that qualify for item (iv) of
subparagraph (K) of this paragraph (1);
(vii) all new photovoltaic distributed
renewable energy generation devices that (1)
qualify for item (i) of subparagraph (K) of this
paragraph (1); (2) are not projects that serve
single-family or multi-family residential
buildings; and (3) are not houses of worship where
the aggregate capacity including colocated
projects would not exceed 100 kilowatts;
(viii) all new photovoltaic distributed
renewable energy generation devices that (1)
qualify for item (ii) of subparagraph (K) of this

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paragraph (1); (2) are not projects that serve
single-family or multi-family residential
buildings; and (3) are not houses of worship where
the aggregate capacity including colocated
projects would not exceed 100 kilowatts;
(ix) all new, modernized, or retooled
hydropower facilities;
(x) all new geothermal heating and cooling
systems awarded through the Geothermal Homes and
Businesses Program under subparagraph (S) of this
paragraph (1) that do not serve (1) single-family
residential buildings, (2) multi-family
residential buildings with aggregate geothermal
system tonnage, including colocated projects, of
no more than 29 tons, or (3) houses of worship with
aggregate geothermal system tonnage, including
colocated projects, of no more than 29 tons.
(2) Renewable energy credits procured from new
utility-scale wind projects, new utility-scale solar
projects, new brownfield solar projects, repowered
wind projects, and retooled hydropower facilities
pursuant to Agency procurement events occurring after
the effective date of this amendatory Act of the 102nd
General Assembly and community-driven community solar
projects or photovoltaic community renewable
generation projects where the aggregate capacity,

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including colocated projects, exceeds 3,000 kilowatts
pursuant to a renewable energy credit delivery
contract approved by the Illinois Commerce Commission
under the Adjustable Block Program after the effective
date of this amendatory Act of the 104th General
Assembly must be from facilities built by general
contractors that must enter into a project labor
agreement, as defined by this Act, prior to
construction. Community-driven community solar
projects and photovoltaic Photovoltaic community
renewable generation projects on a program waitlist as
of the effective date of this amendatory Act of the
104th General Assembly awarded capacity for the
program year commencing June 1, 2026 or any program
year thereafter shall not be exempt from the project
labor agreement requirements of this item (2). The
project labor agreement shall be filed with the
Director in accordance with procedures established by
the Agency through its long-term renewable resources
procurement plan. Any information submitted to the
Agency in this item (2) shall be considered
commercially sensitive information. At a minimum, the
project labor agreement must provide the names,
addresses, and occupations of the owner of the plant
and the individuals representing the labor
organization employees participating in the project

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labor agreement consistent with the Project Labor
Agreements Act. The agreement must also specify the
terms and conditions as defined by this Act.
(2.5) Energy storage credits procured from battery
storage projects pursuant to Agency procurement events
and additional energy storage resources procured in
accordance with subparagraph (B) of paragraph (3) of
subsection (d-20) of this Section pursuant to Agency
procurement events occurring after the effective date
of this amendatory Act of the 104th General Assembly
must be from facilities built by general contractors
that must enter into a project labor agreement prior
to construction. The project labor agreement shall be
filed with the Director in accordance with procedures
established by the Agency through its long-term
renewable resources procurement plan. Any information
submitted to the Agency pursuant to this item (2.5)
shall be considered commercially sensitive
information. At a minimum, the project labor agreement
must provide the names, addresses, and occupations of
the owner of the plant and the individuals
representing the labor organization employees
participating in the project labor agreement
consistent with the Project Labor Agreements Act. The
agreement must also specify the terms and conditions,
as defined by this Act.

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(3) It is the intent of this Section to ensure that
economic development occurs across Illinois
communities, that emerging businesses may grow, and
that there is improved access to the clean energy
economy by persons who have greater economic burdens
to success. The Agency shall take into consideration
the unique cost of compliance of this subparagraph (Q)
that might be borne by equity eligible contractors,
shall include such costs when determining the price of
renewable energy credits in the Adjustable Block
program and the Geothermal Homes and Businesses
Program, and shall take such costs into consideration
in a nondiscriminatory manner when comparing bids for
competitive procurements. The Agency shall consider
costs associated with compliance whether in the
development, financing, or construction of projects.
The Agency shall periodically review the assumptions
in these costs and may adjust prices, in compliance
with subparagraph (M) of this paragraph (1).
(R) In its long-term renewable resources procurement
plan, the Agency shall establish a self-direct renewable
portfolio standard compliance program for eligible
self-direct customers that purchase renewable energy
credits from utility-scale wind and solar projects through
long-term agreements for purchase of renewable energy
credits as described in this Section. Such long-term

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agreements may include the purchase of energy or other
products on a physical or financial basis and may involve
an alternative retail electric supplier as defined in
Section 16-102 of the Public Utilities Act. This program
shall take effect in the delivery year commencing June 1,
2023.
(1) For the purposes of this subparagraph:
"Eligible self-direct customer" means any retail
customers of an electric utility that serves 3,000,000
or more retail customers in the State and whose total
highest 30-minute demand was more than 10,000
kilowatts, or any retail customers of an electric
utility that serves less than 3,000,000 retail
customers but more than 500,000 retail customers in
the State and whose total highest 15-minute demand was
more than 10,000 kilowatts.
"Retail customer" has the meaning set forth in
Section 16-102 of the Public Utilities Act and
multiple retail customer accounts under the same
corporate parent may aggregate their account demands
to meet the 10,000 kilowatt threshold. The criteria
for determining whether this subparagraph is
applicable to a retail customer shall be based on the
12 consecutive billing periods prior to the start of
the year in which the application is filed.
(2) For renewable energy credits to count toward

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the self-direct renewable portfolio standard
compliance program, they must:
(i) qualify as renewable energy credits as
defined in Section 1-10 of this Act;
(ii) be sourced from one or more renewable
energy generating facilities that comply with the
geographic requirements as set forth in
subparagraph (I) of paragraph (1) of subsection
(c) as interpreted through the Agency's long-term
renewable resources procurement plan, or, where
applicable, the geographic requirements that
governed utility-scale renewable energy credits at
the time the eligible self-direct customer entered
into the applicable renewable energy credit
purchase agreement;
(iii) be procured through long-term contracts
with term lengths of at least 10 years either
directly with the renewable energy generating
facility or through a bundled power purchase
agreement, a virtual power purchase agreement, an
agreement between the renewable generating
facility, an alternative retail electric supplier,
and the customer, or such other structure as is
permissible under this subparagraph (R);
(iv) be equivalent in volume to at least 40%
of the eligible self-direct customer's usage,

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determined annually by the eligible self-direct
customer's usage during the previous delivery
year, measured to the nearest megawatt-hour;
(v) be retired by or on behalf of the large
energy customer;
(vi) be sourced from new utility-scale wind
projects or new utility-scale solar projects; and
(vii) if the contracts for renewable energy
credits are entered into after the effective date
of this amendatory Act of the 102nd General
Assembly, the new utility-scale wind projects or
new utility-scale solar projects must comply with
the requirements established in subparagraphs (P)
and (Q) of paragraph (1) of this subsection (c)
and subsection (c-10).
(3) The self-direct renewable portfolio standard
compliance program shall be designed to allow eligible
self-direct customers to procure new renewable energy
credits from new utility-scale wind projects or new
utility-scale photovoltaic projects. The Agency shall
annually determine the amount of utility-scale
renewable energy credits it will include each year
from the self-direct renewable portfolio standard
compliance program, subject to receiving qualifying
applications. In making this determination, the Agency
shall evaluate publicly available analyses and studies

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of the potential market size for utility-scale
renewable energy long-term purchase agreements by
commercial and industrial energy customers and make
that report publicly available. If demand for
participation in the self-direct renewable portfolio
standard compliance program exceeds availability, the
Agency shall ensure participation is evenly split
between commercial and industrial users to the extent
there is sufficient demand from both customer classes.
Each renewable energy credit procured pursuant to this
subparagraph (R) by a self-direct customer shall
reduce the total volume of renewable energy credits
the Agency is otherwise required to procure from new
utility-scale projects pursuant to subparagraph (C) of
paragraph (1) of this subsection (c) on behalf of
contracting utilities where the eligible self-direct
customer is located. The self-direct customer shall
file an annual compliance report with the Agency
pursuant to terms established by the Agency through
its long-term renewable resources procurement plan to
be eligible for participation in this program.
Customers must provide the Agency with their most
recent electricity billing statements or other
information deemed necessary by the Agency to
demonstrate they are an eligible self-direct customer.
(4) The Commission shall approve a reduction in

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the volumetric charges collected pursuant to Section
16-108 of the Public Utilities Act for approved
eligible self-direct customers equivalent to the
anticipated cost of renewable energy credit deliveries
under contracts for new utility-scale wind and new
utility-scale solar entered for each delivery year
after the large energy customer begins retiring
eligible new utility-scale renewable energy credits
for self-compliance. The self-direct credit amount
shall be determined annually and is equal to the
estimated portion of the cost authorized by
subparagraph (E) of paragraph (1) of this subsection
(c) that supported the annual procurement of
utility-scale renewable energy credits in the prior
delivery year using a methodology described in the
long-term renewable resources procurement plan,
expressed on a per kilowatthour basis, and does not
include (i) costs associated with any contracts
entered into before the delivery year in which the
customer files the initial compliance report to be
eligible for participation in the self-direct program,
and (ii) costs associated with procuring renewable
energy credits through existing and future contracts
through the Adjustable Block Program, subsection (c-5)
of this Section 1-75, and the Solar for All Program.
The Agency shall assist the Commission in determining

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the current and future costs. The Agency must
determine the self-direct credit amount for new and
existing eligible self-direct customers and submit
this to the Commission in an annual compliance filing.
The Commission must approve the self-direct credit
amount by June 1, 2023 and June 1 of each delivery year
thereafter.
(5) Customers described in this subparagraph (R)
shall apply, on a form developed by the Agency, to the
Agency to be designated as a self-direct eligible
customer. Once the Agency determines that a
self-direct customer is eligible for participation in
the program, the self-direct customer will remain
eligible until the end of the term of the contract.
Thereafter, application may be made not less than 12
months before the filing date of the long-term
renewable resources procurement plan described in this
Act. At a minimum, such application shall contain the
following:
(i) the customer's certification that, at the
time of the customer's application, the customer
qualifies to be a self-direct eligible customer,
including documents demonstrating that
qualification;
(ii) the customer's certification that the
customer has entered into or will enter into by

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the beginning of the applicable procurement year,
one or more bilateral contracts for new wind
projects or new photovoltaic projects, including
supporting documentation;
(iii) certification that the contract or
contracts for new renewable energy resources are
long-term contracts with term lengths of at least
10 years, including supporting documentation;
(iv) certification of the quantities of
renewable energy credits that the customer will
purchase each year under such contract or
contracts, including supporting documentation;
(v) proof that the contract is sufficient to
produce renewable energy credits to be equivalent
in volume to at least 40% of the large energy
customer's usage from the previous delivery year,
measured to the nearest megawatt-hour; and
(vi) certification that the customer intends
to maintain the contract for the duration of the
length of the contract.
(6) If a customer receives the self-direct credit
but fails to properly procure and retire renewable
energy credits as required under this subparagraph
(R), the Commission, on petition from the Agency and
after notice and hearing, may direct such customer's
utility to recover the cost of the wrongfully received

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self-direct credits plus interest through an adder to
charges assessed pursuant to Section 16-108 of the
Public Utilities Act. Self-direct customers who
knowingly fail to properly procure and retire
renewable energy credits and do not notify the Agency
are ineligible for continued participation in the
self-direct renewable portfolio standard compliance
program.
(S) Beginning with the long-term renewable resources
procurement plan covering program and procurement activity
for the delivery year beginning on June 1, 2028, any
long-term renewable resources procurement plan developed
by the Agency in accordance with subparagraph (A) of this
paragraph (1) shall include a Geothermal Homes and
Businesses Program for the procurement of geothermal
renewable energy credits from new geothermal heating and
cooling systems. The long-term renewable resources
procurement plan shall allocate up to $10,000,000 per
delivery year to fund the Program as described in this
subparagraph (S). The Program shall be designed to
stimulate the steady, predictable, and sustainable growth
of new geothermal heating and cooling system deployment in
this State and meet gaps in the marketplace. To this end,
the Geothermal Homes and Businesses Program shall provide
a transparent annual schedule of prices and quantities to
enable the geothermal heating and cooling market to scale

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up and renewable energy credit prices to adjust at a
predictable rate over time. The prices set by the
Geothermal Homes and Businesses Program may be reflected
as a set value or as the product of a formula.
(i) The Geothermal Homes and Businesses Program
shall allocate blocks of renewable energy credits as
follows:
(1) The Agency may create categories for the
Program based on structure features and use cases,
including categories based on the nature and size
of the Program's projects, customers, communities
in which a project is located, and other
attributes, defined at the discretion of the
Agency through its long-term plan.
(2) The Agency shall propose an initial single
annual block for each Program delivery year for
each category it creates through the delivery year
beginning on June 1, 2035. The Program shall
include the following for eligible projects for
each delivery year: (I) a block of geothermal
renewable energy credit volumes; (II) a price for
renewable energy credits from geothermal heating
and cooling systems within the identified block;
and (III) the terms and conditions for securing a
spot on a waitlist once the block is fully
committed or reserved. The Agency may periodically

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review its prior decisions establishing the amount
of geothermal renewable energy credit volumes in
each annual block and the purchase price for each
block and may propose, on an expedited basis,
changes to the previously set values, including,
but not limited to, redistributing the amounts and
the available funds as necessary and appropriate,
subject to Commission approval. The Agency may
define different block sizes, purchase prices, or
other distinct terms and conditions for projects
located in different utility service territories
if the Agency deems it necessary.
(3) The Agency may develop an intra-year and
year-to-year waitlist and block reservation policy
that balances market certainty, program
availability, and expedient project deployment.
(4) For the program year beginning on June 1,
2028, at least 33% of each annual block shall be
available to be reserved for systems that are
residential, as defined by the Agency. The Agency
shall endeavor to ensure at least 40% of each
annual block is available to be reserved by
systems located in Equity Investment Eligible
Communities. At least 10% of all annual blocks
shall be available to be reserved by systems from
applicants that are equity eligible contractors,

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and the Agency shall propose to increase the
percentage of systems from applicants that are
equity eligible contractors over time to 40% based
on factors that include, but are not limited to,
the number of equity eligible contractors and the
volume used under this clause (4) in previous
delivery years. For long-term renewable resources
procurement plans developed thereafter, the Agency
may propose adjustments to the minimum percentages
based on developer interest, market interest and
availability, and other factors.
(5) The Agency shall establish Program
eligibility requirements that ensure that systems
that enter the Program are sufficiently mature
enough to indicate a demonstrable path to
completion and other terms, conditions, and
requirements for the program, including vendor
registration and approval, sales and marketing
requirements, and other consumer protection
requirements as the Agency deems necessary.
(6) The Program shall be designed to ensure
that geothermal renewable energy credits are
procured from projects in diverse locations and
are not procured from projects that are
concentrated in a few regional areas.
(7) The Agency, through its long-term

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renewable resources procurement plan, may
implement solutions to maintain stable and
consistent REC offerings to avoid gaps in
availability during a delivery year, including,
but not limited to, creating a floating block of
REC capacity in a given delivery year.
(ii) Energy derived from a geothermal heating and
cooling system shall be eligible for inclusion in
meeting the requirements of the Program. Geothermal
renewable energy credits shall be expressed in
megawatt-hour units. To make this calculation, the
Agency (1) shall identify an appropriate formula
supported by a geothermal industry trade organization,
a national laboratory, or another data-backed and
verifiable methodology, (2) may propose adjustments to
any formulas for its proposed renewable energy credit
calculation methodology, and (3) may reflect
calculation methodologies already in use for other
State renewable portfolio standards, if applicable and
appropriate. The Agency shall determine the form and
manner in which the renewable energy credits are
verified and retired, in accordance with national best
practices.
Geothermal renewable energy credits retired by
obligated utilities for compliance with the Program
are only valid for compliance if those geothermal

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renewable energy credits have not been previously
retired by another entity that is not the obligated
utility on any tracking system, carbon registry, or
other accounting mechanism at any time. Additionally,
geothermal renewable energy credits retired by
obligated utilities for compliance with the Program
shall only be valid for compliance if those geothermal
renewable energy credits have not been used to
substantiate a public emissions or energy usage claim
by any other another entity that is not the obligated
utility, of any type and at any time, whether or not
the geothermal renewable energy credits were actually
retired on a tracking system, registry, or other
accounting mechanism at the time of the public
emissions-based claim. Geothermal renewable energy
credits generated for compliance with the Program
shall be valid only if retired once, and claimed once,
by the obligated utility.
In order to promote the competitive development of
geothermal heating and cooling systems in furtherance
of this State's interest in the health, safety, and
welfare of its residents, renewable energy credits
from geothermal heating and cooling systems shall not
be eligible for purchase and retirement under this Act
if the credits are sourced from a geothermal heating
and cooling system for which costs are being recovered

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on or after the effective date of this amendatory Act
of the 104th General Assembly through rates regulated
by this State or any other state.
(iii) The Agency shall establish Program
requirements and minimum contract terms to ensure that
projects are properly installed and that projects
operate to the level of expected benefits. The
contract terms shall include, but are not limited to,
the following:
(1) The capital that is not advanced shall be
disbursed upon a schedule determined by the
Agency, based on the total contracted fulfillment
over the delivery term, not to exceed, during each
delivery year, the contract price multiplied by
the estimated annual renewable energy credit
generation amount. Payment structures shall
include provisions that provide portions of the
renewable energy credit delivery contract value
upon energization, including no less than 40% of
the contract value for residential projects, based
on the estimated renewable energy credit
production during the contract term.
(2) For renewable energy credits that qualify
and are procured under the Program, the delivery
contract length shall be 15 years.
(3) For contracts that are paid upon the

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delivery of renewable energy credits, if
generation of renewable energy credits from
geothermal heating and cooling systems during a
delivery year exceeds the estimated annual
generation amount, the excess of such renewable
energy credits shall be carried forward to future
delivery years and shall not expire during the
delivery term. If the renewable energy credit
generation during a delivery year, including any
carried forward excess renewable energy credits,
is less than the estimated annual generation
amount, payments during the delivery year shall
not exceed the quantity generated plus the
quantity carried forward multiplied by the
contract price. The electric utility shall receive
all renewable energy credits generated by the
project during the first 15 years of operation,
and retire all renewable energy credits paid for
under this clause (3) and return at the end of the
delivery term all geothermal renewable energy
credits that were not paid for. Renewable energy
credits generated by the project thereafter shall
not be transferred under the renewable energy
credit delivery contract with the counterparty
electric utility.
(4) For renewable energy contracts for any

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type of community, shared, or similar geothermal
heating and cooling system that operates using a
subscription model and for which subscriptions are
a basis for contractual payments, subscription of
90% of total renewable energy credit volumes or
greater shall be deemed to be fully subscribed.
(5) Beginning with the long-term renewable
resources procurement plan covering the delivery
year beginning on June 1, 2030, the Agency may
propose a payment structure for Program contracts
upon a demonstration of qualification or need
under criteria established by the Agency that is
focused on supporting the small and emerging
businesses and the businesses that most acutely
face barriers to capital access. Successful
applicant firms shall have advanced capital
disbursed before renewable energy credits are
first generated. The maximum amount or percentage
of capital advanced shall be included in the
long-term renewable resources procurement plan,
and any amount actually advanced shall be designed
to overcome the barriers in access to capital that
are faced by an applicant through that applicant's
demonstration of need. The amount or percentage of
advanced capital may vary by year, or inter-year,
by structure category, block, and other factors as

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deemed applicable by the Agency and by an
applicant's demonstration of need. Contracts
featuring capital advanced prior to system
operation shall feature provisions to ensure both
the successful development of applicant projects
and the delivery of renewable energy credits for
the full term of the contract, including ongoing
collateral requirements and other provisions
deemed necessary by the Agency. The percentage or
amount of capital advanced prior to system
operation shall not increase the overall contract
value.
(6) Each contract shall include provisions to
ensure the delivery of the estimated quantity of
geothermal renewable energy credits, including a
requirement of performance assurance in an amount
deemed appropriate by the Agency.
(7) An obligated utility shall be the
counterparty to the contracts executed under this
subparagraph (S) that are approved by the
Commission. No contract shall be executed for an
amount that is less than one geothermal renewable
energy credit per year.
(8) Nothing in this subparagraph (S) shall
require the utility to advance any payment or pay
any amounts that exceed the actual amount of

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revenues anticipated to be collected by the
utility inclusive of eligible funds collected in
prior years and alternative compliance payments
for use by the utility.
(9) Contracts may be assignable, but only to
entities first deemed by the Agency to have met
Program terms and requirements applicable to
direct Program participation. In developing
contracts for the delivery of renewable energy
credits from geothermal heating and cooling
systems, the Agency may establish fees applicable
to each contract assignment.
(10) If, at any time, approved applications
for the Program exceed funds collected by the
electric utility or would cause the Agency to
exceed the limitation on the amount of renewable
energy resources that may be procured, then the
Agency may consider future uncommitted funds to be
reserved for these contracts on a first-come,
first-served basis.
(iv) In order to advance priority access to the
clean energy economy for businesses and workers from
communities that have been excluded from economic
opportunities in the energy sector, been subject to
disproportionate levels of pollution, and
disproportionately experienced negative public health

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outcomes, the Agency shall apply its equity
accountability system and minimum equity standards
established under subsections (c-10), (c-15), (c-20),
(c-25), and (c-30) to geothermal heating and cooling
system renewable energy credit procurement and
programs and may include any proposed modifications to
the equity accountability system and minimum equity
standards that may be warranted with respect to
geothermal heating and cooling systems in its plan
submission to the Commission under Section 16-111.5 of
the Public Utilities Act.
(v) Projects shall be developed in compliance with
the prevailing wage and project labor agreement
requirements, as applicable, for renewable energy
projects in subparagraph (Q) of paragraph (1) of
subsection (c). Projects approved under this Program
are subject to the prevailing wage requirements
outlined in subitem (x) of item (1) of subparagraph
(Q) of paragraph (1) of this subsection (c). Renewable
energy credits for any single geothermal heating and
cooling project that is 142 tons or larger and is
procured under this Program after the effective date
of this amendatory Act of the 104th General Assembly
shall only be eligible if the associated project was
built by general contractors who entered into a
project labor agreement prior to construction. The

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project labor agreement shall be filed with the
Director in accordance with procedures established by
the Agency through its long-term renewable resources
procurement plan. The project labor agreement shall
provide the names, addresses, and occupations of the
owner of the plant and the individuals representing
the labor organization employees that participate in
the project labor agreement. The project labor
agreement shall also specify terms and conditions as
provided in this Act.
(vi) The Agency shall strive to minimize
administrative expenses in the implementation of the
Program. The Agency may use any existing program
administrator and any applicable subcontractors to
develop, administer, implement, operate, and evaluate
the Program.
(T) Renewable energy credits procured under Agency
procurements or programs for community solar projects with
more than 3 megawatts in nameplate capacity must be
procured from facilities built by general contractors
that, prior to construction, enter into a project labor
agreement, as defined by this Act, subject to the
following requirements and limitations:
(i) The project labor agreement shall be filed
with the Director in accordance with procedures
established by the Agency through its long-term

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renewable resources procurement plan. Any information
submitted to the Agency under this item (i) shall be
considered commercially sensitive information.
(ii) At a minimum, the project labor agreement
must provide the names, addresses, and occupations of
the owner of the project and any individuals
representing the labor organization of the employees
participating in the project labor agreement
consistent with the Project Labor Agreements Act. The
project labor agreement must also meet the terms and
conditions, as set forth in this Act.
(iii) It is the intent of this Section to ensure
that economic development occurs across communities in
this State, that emerging businesses may grow, and
that there is improved access to the clean energy
economy by persons who have greater economic burdens
to success. The Agency shall take into consideration
the unique cost of compliance of this subparagraph (T)
that may be borne by equity eligible contractors and
shall include those costs when determining the price
of renewable energy credits in the Adjustable Block
program. The Agency shall consider costs associated
with compliance, including in the development,
financing, or construction of projects. The Agency
shall periodically review the assumptions in these
costs and may adjust prices in compliance with

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

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

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

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Section 1-75. The renewable energy credits procured
pursuant to this subsection (c-5) may be included or
counted for purposes of compliance with the amounts of
renewable energy credits required to be procured pursuant
to subsection (c) of this Section to the extent that there
are otherwise shortfalls in compliance with such
requirements. The procurement of renewable energy credits
by electric utilities pursuant to this subsection (c-5)
shall be funded solely by revenues collected from the Coal
to Solar and Energy Storage Initiative Charge provided for
in this subsection (c-5) and subsection (i-5) of Section
16-108 of the Public Utilities Act, shall not be funded by
revenues collected through any of the other funding
mechanisms provided for in subsection (c) of this Section,
and shall not be subject to the limitation imposed by
subsection (c) on charges to retail customers for costs to
procure renewable energy resources pursuant to subsection
(c), and shall not be subject to any other requirements or
limitations of subsection (c).
(2) The Agency shall conduct 2 procurement events to
select owners of electric generating facilities meeting
the eligibility criteria specified in this subsection
(c-5) to enter into long-term contracts to sell renewable
energy credits to electric utilities serving more than
300,000 retail customers in this State as of January 1,
2019. The first procurement event shall be conducted no

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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this paragraph (11) shall be referred to as the EPC
contractor, to enable diverse businesses to be
considered fairly for selection to provide materials
and services; (ii) requirements for the applicant or
owner or its EPC contractor to proactively solicit and
utilize diverse businesses to provide materials and
services; and (iii) requirements for the applicant or
owner or its EPC contractor to hire a diverse
workforce for the project. The plan shall include a
description of the applicant's or owner's diversity
recruiting efforts both for the project and for other
areas of the applicant's or owner's business
operations. The plan shall provide for the imposition
of financial penalties on the applicant's or owner's
EPC contractor for failure to exercise best efforts to
comply with and execute the EPC contractor's diversity
obligations under the plan. The plan may provide for
the applicant or owner to set aside a portion of the
work on the project to serve as an incubation program
for qualified businesses, as specified in the plan,
owned by minority persons, women, persons with
disabilities, LGBTQ persons, and veterans, and
businesses located in environmental justice
communities, seeking to enter the renewable energy
industry.
(D) The applicant or owner may submit a revised or

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

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

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increases to the minimum equity standards in its draft
revised renewable energy resources procurement plan
submitted to the Commission for approval pursuant to
paragraph (5) of subsection (b) of Section 16-111.5 of the
Public Utilities Act. In determining these annual
increases, the Agency shall have the discretion to
establish different minimum equity standards for different
types of procurements and different regions of the State
if the Agency finds that doing so will further the
purposes of this subsection (c-10). The proposed schedule
of annual increases shall be revisited and updated on an
annual basis. Revisions shall be developed with
stakeholder input, including from equity eligible persons,
equity eligible contractors, clean energy industry
representatives, and community-based organizations that
work with such persons and contractors.
(A) At the start of each delivery year, the Agency
shall require a compliance plan from each entity
participating in a procurement program of subsection
(c) of this Section, and entities opting to comply
with the minimum equity standard through the Illinois
Solar for All Program under Section 1-56 of this Act,
that demonstrates how they will achieve compliance
with the minimum equity standard percentage for work
completed in that delivery year. If an entity applies
for its approved vendor or designee status between

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

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

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

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paragraph (1) of subsection (c) and in meeting the
minimum equity standards of this subsection (c-10).
(D) A process for certifying equity eligible
contractors and equity eligible persons. The
certification process shall coordinate with the Energy
Workforce Equity Database set forth in subsection
(c-25).
(E) An application for waiver of the minimum
equity standards of this subsection, which the Agency
shall have the discretion to grant in rare
circumstances. The Agency may grant such a waiver
where the applicant provides evidence of significant
efforts toward meeting the minimum equity commitment,
including: use of the Energy Workforce Equity
Database; efforts to hire or contract with entities
that hire eligible persons; and efforts to establish
contracting relationships with eligible contractors.
The Agency shall support applicants in understanding
the Energy Workforce Equity Database and other
resources for pursuing compliance of the minimum
equity standards. Waivers shall be project-specific,
unless the Agency deems it necessary to grant a waiver
across a portfolio of projects, and in effect for no
longer than one year. Any waiver extension or
subsequent waiver request from an applicant shall be
subject to the requirements of this Section and shall

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specify efforts made to reach compliance. When
considering whether to grant a waiver, and to what
extent, the Agency shall consider the degree to which
similarly situated applicants have been able to meet
these minimum equity commitments. For repeated waiver
requests for specific lack of eligible persons or
eligible contractors available, the Agency shall make
recommendations to target recruitment to add such
eligible persons or eligible contractors to the
database.
(5) The Agency shall collect information about work on
projects or portfolios of projects subject to these
minimum equity standards to ensure compliance with this
subsection (c-10). Reporting in furtherance of this
requirement may be combined with other annual reporting
requirements. Such reporting shall include proof of
certification of each equity eligible contractor or equity
eligible person during the applicable time period.
As part of the reporting requirement under this
subparagraph (5), the Agency shall collect and report
information about the use of equity eligible contractors
and equity eligible persons, as well as Minimum Equity
Standard compliance and waiver usage on the Adjustable
Block program and utility-scale projects subject to
project labor agreements. The Agency shall note any
instances of the projects being unable to meet or

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requiring a waiver to meet Minimum Equity Standard
requirements and the location of those projects.
On an annual basis, the Agency shall submit a written
summary of its findings on an annual basis to the General
Assembly and the Governor and shall make the report and
summary available on the Agency's website.
(6) The Agency shall keep confidential all information
and communication that provides private or personal
information.
(7) Modifications to the equity accountability system.
As part of the update of the long-term renewable resources
procurement plan to be initiated in 2023, or sooner if the
Agency deems necessary, the Agency shall determine the
extent to which the equity accountability system described
in this subsection (c-10) has advanced the goals of this
amendatory Act of the 102nd General Assembly, including
through the inclusion of equity eligible persons and
equity eligible contractors in renewable energy credit
projects. If the Agency finds that the equity
accountability system has failed to meet those goals to
its fullest potential, the Agency may revise the following
criteria for future Agency procurements: (A) the
percentage of project workforce, or other appropriate
workforce measure, certified as equity eligible persons or
equity eligible contractors; (B) definitions for equity
investment eligible persons and equity investment eligible

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community; and (C) such other modifications necessary to
advance the goals of this amendatory Act of the 102nd
General Assembly effectively. Such revised criteria may
also establish distinct equity accountability systems for
different types of procurements or different regions of
the State if the Agency finds that doing so will further
the purposes of such programs. Revisions shall be
developed with stakeholder input, including from equity
eligible persons, equity eligible contractors, and
community-based organizations that work with such persons
and contractors.
(c-15) Racial discrimination elimination powers and
process.
(1) Purpose. It is the purpose of this subsection to
empower the Agency and other State actors to remedy racial
discrimination in Illinois' clean energy economy as
effectively and expediently as possible, including through
the use of race-conscious remedies, such as race-conscious
contracting and hiring goals, as consistent with State and
federal law.
(2) Racial disparity and discrimination review
process.
(A) Within one year after awarding contracts using
the equity actions processes established in this
Section, the Agency shall publish a report evaluating
the effectiveness of the equity actions point criteria

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of this Section in increasing participation of equity
eligible persons and equity eligible contractors. The
report shall disaggregate participating workers and
contractors by race and ethnicity. The report shall be
forwarded to the Governor, the General Assembly, and
the Illinois Commerce Commission and be made available
to the public.
(B) As soon as is practicable thereafter, the
Agency, in consultation with the Department of
Commerce and Economic Opportunity, Department of
Labor, and other agencies that may be relevant, shall
commission and publish a disparity and availability
study that measures the presence and impact of
discrimination on minority businesses and workers in
Illinois' clean energy economy. The Agency may hire
consultants and experts to conduct the disparity and
availability study, with the retention of those
consultants and experts exempt from the requirements
of Section 20-10 of the Illinois Procurement Code. The
Illinois Power Agency shall forward a copy of its
findings and recommendations to the Governor, the
General Assembly, and the Illinois Commerce
Commission. If the disparity and availability study
establishes a strong basis in evidence that there is
discrimination in Illinois' clean energy economy, the
Agency, Department of Commerce and Economic

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Opportunity, Department of Labor, Department of
Corrections, and other appropriate agencies shall take
appropriate remedial actions, including race-conscious
remedial actions as consistent with State and federal
law, to effectively remedy this discrimination. Such
remedies may include modification of the equity
accountability system as described in subsection
(c-10).
(c-20) Program data collection.
(1) Purpose. Data collection, data analysis, and
reporting are critical to ensure that the benefits of the
clean energy economy provided to Illinois residents and
businesses are equitably distributed across the State. The
Agency shall collect data from program applicants in order
to track and improve equitable distribution of benefits
across Illinois communities for all procurements the
Agency conducts. The Agency shall use this data to, among
other things, measure any potential impact of racial
discrimination on the distribution of benefits and provide
information necessary to correct any discrimination
through methods consistent with State and federal law.
(2) Agency collection of program data. The Agency
shall collect demographic and geographic data for each
entity awarded contracts under any Agency-administered
program.
(3) Required information to be collected. The Agency

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shall collect the following information from applicants
and program participants where applicable:
(A) demographic information, including racial or
ethnic identity for real persons employed, contracted,
or subcontracted through the program and owners of
businesses or entities that apply to receive renewable
energy credits from the Agency;
(B) geographic location of the residency of real
persons employed, contracted, or subcontracted through
the program and geographic location of the
headquarters of the business or entity that applies to
receive renewable energy credits from the Agency; and
(C) any other information the Agency determines is
necessary for the purpose of achieving the purpose of
this subsection.
(4) Publication of collected information. The Agency
shall publish, at least annually, information on the
demographics of program participants on an aggregate
basis.
(5) Nothing in this subsection shall be interpreted to
limit the authority of the Agency, or other agency or
department of the State, to require or collect demographic
information from applicants of other State programs.
(c-25) Energy Workforce Equity Database.
(1) The Agency, in consultation with the Department of
Commerce and Economic Opportunity, shall create an Energy

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Workforce Equity Database, and may contract with a third
party to do so ("database program administrator"). If the
Department decides to contract with a third party, that
third party shall be exempt from the requirements of
Section 20-10 of the Illinois Procurement Code. The Energy
Workforce Equity Database shall be a searchable database
of suppliers, vendors, and subcontractors for clean energy
industries that is:
(A) publicly accessible;
(B) easy for people to find and use;
(C) organized by company specialty or field;
(D) region-specific; and
(E) populated with information including, but not
limited to, contacts for suppliers, vendors, or
subcontractors who are minority and women-owned
business enterprise certified or who participate or
have participated in any of the programs described in
this Act.
(2) The Agency shall create an easily accessible,
public facing online tool using the database information
that includes, at a minimum, the following:
(A) a map of environmental justice and equity
investment eligible communities;
(B) job postings and recruiting opportunities;
(C) a means by which recruiting clean energy
companies can find and interact with current or former

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participants of clean energy workforce training
programs;
(D) information on workforce training service
providers and training opportunities available to
prospective workers;
(E) renewable energy company diversity reporting;
(F) a list of equity eligible contractors with
their contact information, types of work performed,
and locations worked in;
(G) reporting on outcomes of the programs
described in the workforce programs of the Energy
Transition Act, including information such as, but not
limited to, retention rate, graduation rate, and
placement rates of trainees; and
(H) information about the Jobs and Environmental
Justice Grant Program, the Clean Energy Jobs and
Justice Fund, and other sources of capital.
(3) The Agency shall ensure the database is regularly
updated to ensure information is current and shall
coordinate with the Department of Commerce and Economic
Opportunity to ensure that it includes information on
individuals and entities that are or have participated in
the Clean Jobs Workforce Network Program, Clean Energy
Contractor Incubator Program, Returning Residents Clean
Jobs Training Program, or Clean Energy Primes Contractor
Accelerator Program.

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(c-30) Enforcement of minimum equity standards. All
entities seeking renewable energy credits must submit an
annual report to demonstrate compliance with each of the
equity commitments required under subsection (c-10). If the
Agency concludes the entity has not met or maintained its
minimum equity standards required under the applicable
subparagraphs under subsection (c-10), the Agency shall deny
the entity's ability to participate in procurement programs in
subsection (c), including by withholding approved vendor or
designee status. The Agency may require the entity to enter
into a corrective action plan. An entity that is not
recertified for failing to meet required equity actions in
subparagraph (c-10) may reapply once they have a corrective
action plan and achieve compliance with the minimum equity
standards.
(d) Clean coal portfolio standard.
(1) The procurement plans shall include electricity
generated using clean coal. Each utility shall enter into
one or more sourcing agreements with the initial clean
coal facility, as provided in paragraph (3) of this
subsection (d), covering electricity generated by the
initial clean coal facility representing at least 5% of
each utility's total supply to serve the load of eligible
retail customers in 2015 and each year thereafter, as
described in paragraph (3) of this subsection (d), subject
to the limits specified in paragraph (2) of this

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subsection (d). It is the goal of the State that by January
1, 2025, 25% of the electricity used in the State shall be
generated by cost-effective clean coal facilities. For
purposes of this subsection (d), "cost-effective" means
that the expenditures pursuant to such sourcing agreements
do not cause the limit stated in paragraph (2) of this
subsection (d) to be exceeded and do not exceed cost-based
benchmarks, which shall be developed to assess all
expenditures pursuant to such sourcing agreements covering
electricity generated by clean coal facilities, other than
the initial clean coal facility, by the procurement
administrator, in consultation with the Commission staff,
Agency staff, and the procurement monitor and shall be
subject to Commission review and approval.
A utility party to a sourcing agreement shall
immediately retire any emission credits that it receives
in connection with the electricity covered by such
agreement.
Utilities shall maintain adequate records documenting
the purchases under the sourcing agreement to comply with
this subsection (d) and shall file an accounting with the
load forecast that must be filed with the Agency by July 15
of each year, in accordance with subsection (d) of Section
16-111.5 of the Public Utilities Act.
A utility shall be deemed to have complied with the
clean coal portfolio standard specified in this subsection

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(d) if the utility enters into a sourcing agreement as
required by this subsection (d).
(2) For purposes of this subsection (d), the required
execution of sourcing agreements with the initial clean
coal facility for a particular year shall be measured as a
percentage of the actual amount of electricity
(megawatt-hours) supplied by the electric utility to
eligible retail customers in the planning year ending
immediately prior to the agreement's execution. For
purposes of this subsection (d), the amount paid per
kilowatthour means the total amount paid for electric
service expressed on a per kilowatthour basis. For
purposes of this subsection (d), the total amount paid for
electric service includes without limitation amounts paid
for supply, transmission, distribution, surcharges and
add-on taxes.
Notwithstanding the requirements of this subsection
(d), the total amount paid under sourcing agreements with
clean coal facilities pursuant to the procurement plan for
any given year shall be reduced by an amount necessary to
limit the annual estimated average net increase due to the
costs of these resources included in the amounts paid by
eligible retail customers in connection with electric
service to:
(A) in 2010, no more than 0.5% of the amount paid
per kilowatthour by those customers during the year

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ending May 31, 2009;
(B) in 2011, the greater of an additional 0.5% of
the amount paid per kilowatthour by those customers
during the year ending May 31, 2010 or 1% of the amount
paid per kilowatthour by those customers during the
year ending May 31, 2009;
(C) in 2012, the greater of an additional 0.5% of
the amount paid per kilowatthour by those customers
during the year ending May 31, 2011 or 1.5% of the
amount paid per kilowatthour by those customers during
the year ending May 31, 2009;
(D) in 2013, the greater of an additional 0.5% of
the amount paid per kilowatthour by those customers
during the year ending May 31, 2012 or 2% of the amount
paid per kilowatthour by those customers during the
year ending May 31, 2009; and
(E) thereafter, the total amount paid under
sourcing agreements with clean coal facilities
pursuant to the procurement plan for any single year
shall be reduced by an amount necessary to limit the
estimated average net increase due to the cost of
these resources included in the amounts paid by
eligible retail customers in connection with electric
service to no more than the greater of (i) 2.015% of
the amount paid per kilowatthour by those customers
during the year ending May 31, 2009 or (ii) the

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incremental amount per kilowatthour paid for these
resources in 2013. These requirements may be altered
only as provided by statute.
No later than June 30, 2015, the Commission shall
review the limitation on the total amount paid under
sourcing agreements, if any, with clean coal facilities
pursuant to this subsection (d) and report to the General
Assembly its findings as to whether that limitation unduly
constrains the amount of electricity generated by
cost-effective clean coal facilities that is covered by
sourcing agreements.
(3) Initial clean coal facility. In order to promote
development of clean coal facilities in Illinois, each
electric utility subject to this Section shall execute a
sourcing agreement to source electricity from a proposed
clean coal facility in Illinois (the "initial clean coal
facility") that will have a nameplate capacity of at least
500 MW when commercial operation commences, that has a
final Clean Air Act permit on June 1, 2009 (the effective
date of Public Act 95-1027), and that will meet the
definition of clean coal facility in Section 1-10 of this
Act when commercial operation commences. The sourcing
agreements with this initial clean coal facility shall be
subject to both approval of the initial clean coal
facility by the General Assembly and satisfaction of the
requirements of paragraph (4) of this subsection (d) and

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shall be executed within 90 days after any such approval
by the General Assembly. The Agency and the Commission
shall have authority to inspect all books and records
associated with the initial clean coal facility during the
term of such a sourcing agreement. A utility's sourcing
agreement for electricity produced by the initial clean
coal facility shall include:
(A) a formula contractual price (the "contract
price") approved pursuant to paragraph (4) of this
subsection (d), which shall:
(i) be determined using a cost of service
methodology employing either a level or deferred
capital recovery component, based on a capital
structure consisting of 45% equity and 55% debt,
and a return on equity as may be approved by the
Federal Energy Regulatory Commission, which in any
case may not exceed the lower of 11.5% or the rate
of return approved by the General Assembly
pursuant to paragraph (4) of this subsection (d);
and
(ii) provide that all miscellaneous net
revenue, including but not limited to net revenue
from the sale of emission allowances, if any,
substitute natural gas, if any, grants or other
support provided by the State of Illinois or the
United States Government, firm transmission

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rights, if any, by-products produced by the
facility, energy or capacity derived from the
facility and not covered by a sourcing agreement
pursuant to paragraph (3) of this subsection (d)
or item (5) of subsection (d) of Section 16-115 of
the Public Utilities Act, whether generated from
the synthesis gas derived from coal, from SNG, or
from natural gas, shall be credited against the
revenue requirement for this initial clean coal
facility;
(B) power purchase provisions, which shall:
(i) provide that the utility party to such
sourcing agreement shall pay the contract price
for electricity delivered under such sourcing
agreement;
(ii) require delivery of electricity to the
regional transmission organization market of the
utility that is party to such sourcing agreement;
(iii) require the utility party to such
sourcing agreement to buy from the initial clean
coal facility in each hour an amount of energy
equal to all clean coal energy made available from
the initial clean coal facility during such hour
times a fraction, the numerator of which is such
utility's retail market sales of electricity
(expressed in kilowatthours sold) in the State

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

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the utility's service territory in the State
during the prior calendar month and the
denominator of which is the total retail market
sales of electricity (expressed in kilowatthours
sold) in the State by utilities during such prior
month and the sales of electricity (expressed in
kilowatthours sold) in the State by alternative
retail electric suppliers during such prior month
that are subject to the requirements of this
subsection (d) and paragraph (5) of subsection (d)
of Section 16-115 of the Public Utilities Act,
provided that the amount paid by the utility in
any year will be limited by paragraph (2) of this
subsection (d);
(ii) provide that the utility's payment
obligation in respect of the quantity of
electricity determined pursuant to the preceding
clause (i) shall be limited to an amount equal to
(1) the difference between the contract price
determined pursuant to subparagraph (A) of
paragraph (3) of this subsection (d) and the
day-ahead price for electricity delivered to the
regional transmission organization market of the
utility that is party to such sourcing agreement
(or any successor delivery point at which such
utility's supply obligations are financially

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settled on an hourly basis) (the "reference
price") on the day preceding the day on which the
electricity is delivered to the initial clean coal
facility busbar, multiplied by (2) the quantity of
electricity determined pursuant to the preceding
clause (i); and
(iii) not require the utility to take physical
delivery of the electricity produced by the
facility;
(D) general provisions, which shall:
(i) specify a term of no more than 30 years,
commencing on the commercial operation date of the
facility;
(ii) provide that utilities shall maintain
adequate records documenting purchases under the
sourcing agreements entered into to comply with
this subsection (d) and shall file an accounting
with the load forecast that must be filed with the
Agency by July 15 of each year, in accordance with
subsection (d) of Section 16-111.5 of the Public
Utilities Act;
(iii) provide that all costs associated with
the initial clean coal facility will be
periodically reported to the Federal Energy
Regulatory Commission and to purchasers in
accordance with applicable laws governing

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cost-based wholesale power contracts;
(iv) permit the Illinois Power Agency to
assume ownership of the initial clean coal
facility, without monetary consideration and
otherwise on reasonable terms acceptable to the
Agency, if the Agency so requests no less than 3
years prior to the end of the stated contract
term;
(v) require the owner of the initial clean
coal facility to provide documentation to the
Commission each year, starting in the facility's
first year of commercial operation, accurately
reporting the quantity of carbon emissions from
the facility that have been captured and
sequestered and report any quantities of carbon
released from the site or sites at which carbon
emissions were sequestered in prior years, based
on continuous monitoring of such sites. If, in any
year after the first year of commercial operation,
the owner of the facility fails to demonstrate
that the initial clean coal facility captured and
sequestered at least 50% of the total carbon
emissions that the facility would otherwise emit
or that sequestration of emissions from prior
years has failed, resulting in the release of
carbon dioxide into the atmosphere, the owner of

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the facility must offset excess emissions. Any
such carbon offsets must be permanent, additional,
verifiable, real, located within the State of
Illinois, and legally and practicably enforceable.
The cost of such offsets for the facility that are
not recoverable shall not exceed $15 million in
any given year. No costs of any such purchases of
carbon offsets may be recovered from a utility or
its customers. All carbon offsets purchased for
this purpose and any carbon emission credits
associated with sequestration of carbon from the
facility must be permanently retired. The initial
clean coal facility shall not forfeit its
designation as a clean coal facility if the
facility fails to fully comply with the applicable
carbon sequestration requirements in any given
year, provided the requisite offsets are
purchased. However, the Attorney General, on
behalf of the People of the State of Illinois, may
specifically enforce the facility's sequestration
requirement and the other terms of this contract
provision. Compliance with the sequestration
requirements and offset purchase requirements
specified in paragraph (3) of this subsection (d)
shall be reviewed annually by an independent
expert retained by the owner of the initial clean

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coal facility, with the advance written approval
of the Attorney General. The Commission may, in
the course of the review specified in item (vii),
reduce the allowable return on equity for the
facility if the facility willfully fails to comply
with the carbon capture and sequestration
requirements set forth in this item (v);
(vi) include limits on, and accordingly
provide for modification of, the amount the
utility is required to source under the sourcing
agreement consistent with paragraph (2) of this
subsection (d);
(vii) require Commission review: (1) to
determine the justness, reasonableness, and
prudence of the inputs to the formula referenced
in subparagraphs (A)(i) through (A)(iii) of
paragraph (3) of this subsection (d), prior to an
adjustment in those inputs including, without
limitation, the capital structure and return on
equity, fuel costs, and other operations and
maintenance costs and (2) to approve the costs to
be passed through to customers under the sourcing
agreement by which the utility satisfies its
statutory obligations. Commission review shall
occur no less than every 3 years, regardless of
whether any adjustments have been proposed, and

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shall be completed within 9 months;
(viii) limit the utility's obligation to such
amount as the utility is allowed to recover
through tariffs filed with the Commission,
provided that neither the clean coal facility nor
the utility waives any right to assert federal
pre-emption or any other argument in response to a
purported disallowance of recovery costs;
(ix) limit the utility's or alternative retail
electric supplier's obligation to incur any
liability until such time as the facility is in
commercial operation and generating power and
energy and such power and energy is being
delivered to the facility busbar;
(x) provide that the owner or owners of the
initial clean coal facility, which is the
counterparty to such sourcing agreement, shall
have the right from time to time to elect whether
the obligations of the utility party thereto shall
be governed by the power purchase provisions or
the contract for differences provisions;
(xi) append documentation showing that the
formula rate and contract, insofar as they relate
to the power purchase provisions, have been
approved by the Federal Energy Regulatory
Commission pursuant to Section 205 of the Federal

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Power Act;
(xii) provide that any changes to the terms of
the contract, insofar as such changes relate to
the power purchase provisions, are subject to
review under the public interest standard applied
by the Federal Energy Regulatory Commission
pursuant to Sections 205 and 206 of the Federal
Power Act; and
(xiii) conform with customary lender
requirements in power purchase agreements used as
the basis for financing non-utility generators.
(4) Effective date of sourcing agreements with the
initial clean coal facility. Any proposed sourcing
agreement with the initial clean coal facility shall not
become effective unless the following reports are prepared
and submitted and authorizations and approvals obtained:
(i) Facility cost report. The owner of the initial
clean coal facility shall submit to the Commission,
the Agency, and the General Assembly a front-end
engineering and design study, a facility cost report,
method of financing (including but not limited to
structure and associated costs), and an operating and
maintenance cost quote for the facility (collectively
"facility cost report"), which shall be prepared in
accordance with the requirements of this paragraph (4)
of subsection (d) of this Section, and shall provide

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the Commission and the Agency access to the work
papers, relied upon documents, and any other backup
documentation related to the facility cost report.
(ii) Commission report. Within 6 months following
receipt of the facility cost report, the Commission,
in consultation with the Agency, shall submit a report
to the General Assembly setting forth its analysis of
the facility cost report. Such report shall include,
but not be limited to, a comparison of the costs
associated with electricity generated by the initial
clean coal facility to the costs associated with
electricity generated by other types of generation
facilities, an analysis of the rate impacts on
residential and small business customers over the life
of the sourcing agreements, and an analysis of the
likelihood that the initial clean coal facility will
commence commercial operation by and be delivering
power to the facility's busbar by 2016. To assist in
the preparation of its report, the Commission, in
consultation with the Agency, may hire one or more
experts or consultants, the costs of which shall be
paid for by the owner of the initial clean coal
facility. The Commission and Agency may begin the
process of selecting such experts or consultants prior
to receipt of the facility cost report.
(iii) General Assembly approval. The proposed

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sourcing agreements shall not take effect unless,
based on the facility cost report and the Commission's
report, the General Assembly enacts authorizing
legislation approving (A) the projected price, stated
in cents per kilowatthour, to be charged for
electricity generated by the initial clean coal
facility, (B) the projected impact on residential and
small business customers' bills over the life of the
sourcing agreements, and (C) the maximum allowable
return on equity for the project; and
(iv) Commission review. If the General Assembly
enacts authorizing legislation pursuant to
subparagraph (iii) approving a sourcing agreement, the
Commission shall, within 90 days of such enactment,
complete a review of such sourcing agreement. During
such time period, the Commission shall implement any
directive of the General Assembly, resolve any
disputes between the parties to the sourcing agreement
concerning the terms of such agreement, approve the
form of such agreement, and issue an order finding
that the sourcing agreement is prudent and reasonable.
The facility cost report shall be prepared as follows:
(A) The facility cost report shall be prepared by
duly licensed engineering and construction firms
detailing the estimated capital costs payable to one
or more contractors or suppliers for the engineering,

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procurement and construction of the components
comprising the initial clean coal facility and the
estimated costs of operation and maintenance of the
facility. The facility cost report shall include:
(i) an estimate of the capital cost of the
core plant based on one or more front end
engineering and design studies for the
gasification island and related facilities. The
core plant shall include all civil, structural,
mechanical, electrical, control, and safety
systems.
(ii) an estimate of the capital cost of the
balance of the plant, including any capital costs
associated with sequestration of carbon dioxide
emissions and all interconnects and interfaces
required to operate the facility, such as
transmission of electricity, construction or
backfeed power supply, pipelines to transport
substitute natural gas or carbon dioxide, potable
water supply, natural gas supply, water supply,
water discharge, landfill, access roads, and coal
delivery.
The quoted construction costs shall be expressed
in nominal dollars as of the date that the quote is
prepared and shall include capitalized financing costs
during construction, taxes, insurance, and other

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owner's costs, and an assumed escalation in materials
and labor beyond the date as of which the construction
cost quote is expressed.
(B) The front end engineering and design study for
the gasification island and the cost study for the
balance of plant shall include sufficient design work
to permit quantification of major categories of
materials, commodities and labor hours, and receipt of
quotes from vendors of major equipment required to
construct and operate the clean coal facility.
(C) The facility cost report shall also include an
operating and maintenance cost quote that will provide
the estimated cost of delivered fuel, personnel,
maintenance contracts, chemicals, catalysts,
consumables, spares, and other fixed and variable
operations and maintenance costs. The delivered fuel
cost estimate will be provided by a recognized third
party expert or experts in the fuel and transportation
industries. The balance of the operating and
maintenance cost quote, excluding delivered fuel
costs, will be developed based on the inputs provided
by duly licensed engineering and construction firms
performing the construction cost quote, potential
vendors under long-term service agreements and plant
operating agreements, or recognized third party plant
operator or operators.

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The operating and maintenance cost quote
(including the cost of the front end engineering and
design study) shall be expressed in nominal dollars as
of the date that the quote is prepared and shall
include taxes, insurance, and other owner's costs, and
an assumed escalation in materials and labor beyond
the date as of which the operating and maintenance
cost quote is expressed.
(D) The facility cost report shall also include an
analysis of the initial clean coal facility's ability
to deliver power and energy into the applicable
regional transmission organization markets and an
analysis of the expected capacity factor for the
initial clean coal facility.
(E) Amounts paid to third parties unrelated to the
owner or owners of the initial clean coal facility to
prepare the core plant construction cost quote,
including the front end engineering and design study,
and the operating and maintenance cost quote will be
reimbursed through Coal Development Bonds.
(5) Re-powering and retrofitting coal-fired power
plants previously owned by Illinois utilities to qualify
as clean coal facilities. During the 2009 procurement
planning process and thereafter, the Agency and the
Commission shall consider sourcing agreements covering
electricity generated by power plants that were previously

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owned by Illinois utilities and that have been or will be
converted into clean coal facilities, as defined by
Section 1-10 of this Act. Pursuant to such procurement
planning process, the owners of such facilities may
propose to the Agency sourcing agreements with utilities
and alternative retail electric suppliers required to
comply with subsection (d) of this Section and item (5) of
subsection (d) of Section 16-115 of the Public Utilities
Act, covering electricity generated by such facilities. In
the case of sourcing agreements that are power purchase
agreements, the contract price for electricity sales shall
be established on a cost of service basis. In the case of
sourcing agreements that are contracts for differences,
the contract price from which the reference price is
subtracted shall be established on a cost of service
basis. The Agency and the Commission may approve any such
utility sourcing agreements that do not exceed cost-based
benchmarks developed by the procurement administrator, in
consultation with the Commission staff, Agency staff and
the procurement monitor, subject to Commission review and
approval. The Commission shall have authority to inspect
all books and records associated with these clean coal
facilities during the term of any such contract.
(6) Costs incurred under this subsection (d) or
pursuant to a contract entered into under this subsection
(d) shall be deemed prudently incurred and reasonable in

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amount and the electric utility shall be entitled to full
cost recovery pursuant to the tariffs filed with the
Commission.
(d-5) Zero emission standard.
(1) Beginning with the delivery year commencing on
June 1, 2017, the Agency shall, for electric utilities
that serve at least 100,000 retail customers in this
State, procure contracts with zero emission facilities
that are reasonably capable of generating cost-effective
zero emission credits in an amount approximately equal to
16% of the actual amount of electricity delivered by each
electric utility to retail customers in the State during
calendar year 2014. For an electric utility serving fewer
than 100,000 retail customers in this State that
requested, under Section 16-111.5 of the Public Utilities
Act, that the Agency procure power and energy for all or a
portion of the utility's Illinois load for the delivery
year commencing June 1, 2016, the Agency shall procure
contracts with zero emission facilities that are
reasonably capable of generating cost-effective zero
emission credits in an amount approximately equal to 16%
of the portion of power and energy to be procured by the
Agency for the utility. The duration of the contracts
procured under this subsection (d-5) shall be for a term
of 10 years ending May 31, 2027. The quantity of zero
emission credits to be procured under the contracts shall

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be all of the zero emission credits generated by the zero
emission facility in each delivery year; however, if the
zero emission facility is owned by more than one entity,
then the quantity of zero emission credits to be procured
under the contracts shall be the amount of zero emission
credits that are generated from the portion of the zero
emission facility that is owned by the winning supplier.
The 16% value identified in this paragraph (1) is the
average of the percentage targets in subparagraph (B) of
paragraph (1) of subsection (c) of this Section for the 5
delivery years beginning June 1, 2017.
The procurement process shall be subject to the
following provisions:
(A) Those zero emission facilities that intend to
participate in the procurement shall submit to the
Agency the following eligibility information for each
zero emission facility on or before the date
established by the Agency:
(i) the in-service date and remaining useful
life of the zero emission facility;
(ii) the amount of power generated annually
for each of the years 2005 through 2015, and the
projected zero emission credits to be generated
over the remaining useful life of the zero
emission facility, which shall be used to
determine the capability of each facility;

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(iii) the annual zero emission facility cost
projections, expressed on a per megawatthour
basis, over the next 6 delivery years, which shall
include the following: operation and maintenance
expenses; fully allocated overhead costs, which
shall be allocated using the methodology developed
by the Institute for Nuclear Power Operations;
fuel expenditures; non-fuel capital expenditures;
spent fuel expenditures; a return on working
capital; the cost of operational and market risks
that could be avoided by ceasing operation; and
any other costs necessary for continued
operations, provided that "necessary" means, for
purposes of this item (iii), that the costs could
reasonably be avoided only by ceasing operations
of the zero emission facility; and
(iv) a commitment to continue operating, for
the duration of the contract or contracts executed
under the procurement held under this subsection
(d-5), the zero emission facility that produces
the zero emission credits to be procured in the
procurement.
The information described in item (iii) of this
subparagraph (A) may be submitted on a confidential
basis and shall be treated and maintained by the
Agency, the procurement administrator, and the

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Commission as confidential and proprietary and exempt
from disclosure under subparagraphs (a) and (g) of
paragraph (1) of Section 7 of the Freedom of
Information Act. The Office of Attorney General shall
have access to, and maintain the confidentiality of,
such information pursuant to Section 6.5 of the
Attorney General Act.
(B) The price for each zero emission credit
procured under this subsection (d-5) for each delivery
year shall be in an amount that equals the Social Cost
of Carbon, expressed on a price per megawatthour
basis. However, to ensure that the procurement remains
affordable to retail customers in this State if
electricity prices increase, the price in an
applicable delivery year shall be reduced below the
Social Cost of Carbon by the amount ("Price
Adjustment") by which the market price index for the
applicable delivery year exceeds the baseline market
price index for the consecutive 12-month period ending
May 31, 2016. If the Price Adjustment is greater than
or equal to the Social Cost of Carbon in an applicable
delivery year, then no payments shall be due in that
delivery year. The components of this calculation are
defined as follows:
(i) Social Cost of Carbon: The Social Cost of
Carbon is $16.50 per megawatthour, which is based

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on the U.S. Interagency Working Group on Social
Cost of Carbon's price in the August 2016
Technical Update using a 3% discount rate,
adjusted for inflation for each year of the
program. Beginning with the delivery year
commencing June 1, 2023, the price per
megawatthour shall increase by $1 per
megawatthour, and continue to increase by an
additional $1 per megawatthour each delivery year
thereafter.
(ii) Baseline market price index: The baseline
market price index for the consecutive 12-month
period ending May 31, 2016 is $31.40 per
megawatthour, which is based on the sum of (aa)
the average day-ahead energy price across all
hours of such 12-month period at the PJM
Interconnection LLC Northern Illinois Hub, (bb)
50% multiplied by the Base Residual Auction, or
its successor, capacity price for the rest of the
RTO zone group determined by PJM Interconnection
LLC, divided by 24 hours per day, and (cc) 50%
multiplied by the Planning Resource Auction, or
its successor, capacity price for Zone 4
determined by the Midcontinent Independent System
Operator, Inc., divided by 24 hours per day.
(iii) Market price index: The market price

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index for a delivery year shall be the sum of
projected energy prices and projected capacity
prices determined as follows:
(aa) Projected energy prices: the
projected energy prices for the applicable
delivery year shall be calculated once for the
year using the forward market price for the
PJM Interconnection, LLC Northern Illinois
Hub. The forward market price shall be
calculated as follows: the energy forward
prices for each month of the applicable
delivery year averaged for each trade date
during the calendar year immediately preceding
that delivery year to produce a single energy
forward price for the delivery year. The
forward market price calculation shall use
data published by the Intercontinental
Exchange, or its successor.
(bb) Projected capacity prices:
(I) For the delivery years commencing
June 1, 2017, June 1, 2018, and June 1,
2019, the projected capacity price shall
be equal to the sum of (1) 50% multiplied
by the Base Residual Auction, or its
successor, price for the rest of the RTO
zone group as determined by PJM

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Interconnection LLC, divided by 24 hours
per day and, (2) 50% multiplied by the
resource auction price determined in the
resource auction administered by the
Midcontinent Independent System Operator,
Inc., in which the largest percentage of
load cleared for Local Resource Zone 4,
divided by 24 hours per day, and where
such price is determined by the
Midcontinent Independent System Operator,
Inc.
(II) For the delivery year commencing
June 1, 2020, and each year thereafter,
the projected capacity price shall be
equal to the sum of (1) 50% multiplied by
the Base Residual Auction, or its
successor, price for the ComEd zone as
determined by PJM Interconnection LLC,
divided by 24 hours per day, and (2) 50%
multiplied by the resource auction price
determined in the resource auction
administered by the Midcontinent
Independent System Operator, Inc., in
which the largest percentage of load
cleared for Local Resource Zone 4, divided
by 24 hours per day, and where such price

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is determined by the Midcontinent
Independent System Operator, Inc.
For purposes of this subsection (d-5):
"Rest of the RTO" and "ComEd Zone" shall have
the meaning ascribed to them by PJM
Interconnection, LLC.
"RTO" means regional transmission
organization.
(C) No later than 45 days after June 1, 2017 (the
effective date of Public Act 99-906), the Agency shall
publish its proposed zero emission standard
procurement plan. The plan shall be consistent with
the provisions of this paragraph (1) and shall provide
that winning bids shall be selected based on public
interest criteria that include, but are not limited
to, minimizing carbon dioxide emissions that result
from electricity consumed in Illinois and minimizing
sulfur dioxide, nitrogen oxide, and particulate matter
emissions that adversely affect the citizens of this
State. In particular, the selection of winning bids
shall take into account the incremental environmental
benefits resulting from the procurement, such as any
existing environmental benefits that are preserved by
the procurements held under Public Act 99-906 and
would cease to exist if the procurements were not
held, including the preservation of zero emission

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facilities. The plan shall also describe in detail how
each public interest factor shall be considered and
weighted in the bid selection process to ensure that
the public interest criteria are applied to the
procurement and given full effect.
For purposes of developing the plan, the Agency
shall consider any reports issued by a State agency,
board, or commission under House Resolution 1146 of
the 98th General Assembly and paragraph (4) of
subsection (d) of this Section, as well as publicly
available analyses and studies performed by or for
regional transmission organizations that serve the
State and their independent market monitors.
Upon publishing of the zero emission standard
procurement plan, copies of the plan shall be posted
and made publicly available on the Agency's website.
All interested parties shall have 10 days following
the date of posting to provide comment to the Agency on
the plan. All comments shall be posted to the Agency's
website. Following the end of the comment period, but
no more than 60 days later than June 1, 2017 (the
effective date of Public Act 99-906), the Agency shall
revise the plan as necessary based on the comments
received and file its zero emission standard
procurement plan with the Commission.
If the Commission determines that the plan will

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result in the procurement of cost-effective zero
emission credits, then the Commission shall, after
notice and hearing, but no later than 45 days after the
Agency filed the plan, approve the plan or approve
with modification. For purposes of this subsection
(d-5), "cost effective" means the projected costs of
procuring zero emission credits from zero emission
facilities do not cause the limit stated in paragraph
(2) of this subsection to be exceeded.
(C-5) As part of the Commission's review and
acceptance or rejection of the procurement results,
the Commission shall, in its public notice of
successful bidders:
(i) identify how the winning bids satisfy the
public interest criteria described in subparagraph
(C) of this paragraph (1) of minimizing carbon
dioxide emissions that result from electricity
consumed in Illinois and minimizing sulfur
dioxide, nitrogen oxide, and particulate matter
emissions that adversely affect the citizens of
this State;
(ii) specifically address how the selection of
winning bids takes into account the incremental
environmental benefits resulting from the
procurement, including any existing environmental
benefits that are preserved by the procurements

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held under Public Act 99-906 and would have ceased
to exist if the procurements had not been held,
such as the preservation of zero emission
facilities;
(iii) quantify the environmental benefit of
preserving the resources identified in item (ii)
of this subparagraph (C-5), including the
following:
(aa) the value of avoided greenhouse gas
emissions measured as the product of the zero
emission facilities' output over the contract
term multiplied by the U.S. Environmental
Protection Agency eGrid subregion carbon
dioxide emission rate and the U.S. Interagency
Working Group on Social Cost of Carbon's price
in the August 2016 Technical Update using a 3%
discount rate, adjusted for inflation for each
delivery year; and
(bb) the costs of replacement with other
zero carbon dioxide resources, including wind
and photovoltaic, based upon the simple
average of the following:
(I) the price, or if there is more
than one price, the average of the prices,
paid for renewable energy credits from new
utility-scale wind projects in the

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procurement events specified in item (i)
of subparagraph (G) of paragraph (1) of
subsection (c) of this Section; and
(II) the price, or if there is more
than one price, the average of the prices,
paid for renewable energy credits from new
utility-scale solar projects and
brownfield site photovoltaic projects in
the procurement events specified in item
(ii) of subparagraph (G) of paragraph (1)
of subsection (c) of this Section and,
after January 1, 2015, renewable energy
credits from photovoltaic distributed
generation projects in procurement events
held under subsection (c) of this Section.
Each utility shall enter into binding contractual
arrangements with the winning suppliers.
The procurement described in this subsection
(d-5), including, but not limited to, the execution of
all contracts procured, shall be completed no later
than May 10, 2017. Based on the effective date of
Public Act 99-906, the Agency and Commission may, as
appropriate, modify the various dates and timelines
under this subparagraph and subparagraphs (C) and (D)
of this paragraph (1). The procurement and plan
approval processes required by this subsection (d-5)

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shall be conducted in conjunction with the procurement
and plan approval processes required by subsection (c)
of this Section and Section 16-111.5 of the Public
Utilities Act, to the extent practicable.
Notwithstanding whether a procurement event is
conducted under Section 16-111.5 of the Public
Utilities Act, the Agency shall immediately initiate a
procurement process on June 1, 2017 (the effective
date of Public Act 99-906).
(D) Following the procurement event described in
this paragraph (1) and consistent with subparagraph
(B) of this paragraph (1), the Agency shall calculate
the payments to be made under each contract for the
next delivery year based on the market price index for
that delivery year. The Agency shall publish the
payment calculations no later than May 25, 2017 and
every May 25 thereafter.
(E) Notwithstanding the requirements of this
subsection (d-5), the contracts executed under this
subsection (d-5) shall provide that the zero emission
facility may, as applicable, suspend or terminate
performance under the contracts in the following
instances:
(i) A zero emission facility shall be excused
from its performance under the contract for any
cause beyond the control of the resource,

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including, but not restricted to, acts of God,
flood, drought, earthquake, storm, fire,
lightning, epidemic, war, riot, civil disturbance
or disobedience, labor dispute, labor or material
shortage, sabotage, acts of public enemy,
explosions, orders, regulations or restrictions
imposed by governmental, military, or lawfully
established civilian authorities, which, in any of
the foregoing cases, by exercise of commercially
reasonable efforts the zero emission facility
could not reasonably have been expected to avoid,
and which, by the exercise of commercially
reasonable efforts, it has been unable to
overcome. In such event, the zero emission
facility shall be excused from performance for the
duration of the event, including, but not limited
to, delivery of zero emission credits, and no
payment shall be due to the zero emission facility
during the duration of the event.
(ii) A zero emission facility shall be
permitted to terminate the contract if legislation
is enacted into law by the General Assembly that
imposes or authorizes a new tax, special
assessment, or fee on the generation of
electricity, the ownership or leasehold of a
generating unit, or the privilege or occupation of

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such generation, ownership, or leasehold of
generation units by a zero emission facility.
However, the provisions of this item (ii) do not
apply to any generally applicable tax, special
assessment or fee, or requirements imposed by
federal law.
(iii) A zero emission facility shall be
permitted to terminate the contract in the event
that the resource requires capital expenditures in
excess of $40,000,000 that were neither known nor
reasonably foreseeable at the time it executed the
contract and that a prudent owner or operator of
such resource would not undertake.
(iv) A zero emission facility shall be
permitted to terminate the contract in the event
the Nuclear Regulatory Commission terminates the
resource's license.
(F) If the zero emission facility elects to
terminate a contract under subparagraph (E) of this
paragraph (1), then the Commission shall reopen the
docket in which the Commission approved the zero
emission standard procurement plan under subparagraph
(C) of this paragraph (1) and, after notice and
hearing, enter an order acknowledging the contract
termination election if such termination is consistent
with the provisions of this subsection (d-5).

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(2) For purposes of this subsection (d-5), the amount
paid per kilowatthour means the total amount paid for
electric service expressed on a per kilowatthour basis.
For purposes of this subsection (d-5), the total amount
paid for electric service includes, without limitation,
amounts paid for supply, transmission, distribution,
surcharges, and add-on taxes.
Notwithstanding the requirements of this subsection
(d-5), the contracts executed under this subsection (d-5)
shall provide that the total of zero emission credits
procured under a procurement plan shall be subject to the
limitations of this paragraph (2). For each delivery year,
the contractual volume receiving payments in such year
shall be reduced for all retail customers based on the
amount necessary to limit the net increase that delivery
year to the costs of those credits included in the amounts
paid by eligible retail customers in connection with
electric service to no more than 1.65% of the amount paid
per kilowatthour by eligible retail customers during the
year ending May 31, 2009. The result of this computation
shall apply to and reduce the procurement for all retail
customers, and all those customers shall pay the same
single, uniform cents per kilowatthour charge under
subsection (k) of Section 16-108 of the Public Utilities
Act. To arrive at a maximum dollar amount of zero emission
credits to be paid for the particular delivery year, the

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resulting per kilowatthour amount shall be applied to the
actual amount of kilowatthours of electricity delivered by
the electric utility in the delivery year immediately
prior to the procurement, to all retail customers in its
service territory. Unpaid contractual volume for any
delivery year shall be paid in any subsequent delivery
year in which such payments can be made without exceeding
the amount specified in this paragraph (2). The
calculations required by this paragraph (2) shall be made
only once for each procurement plan year. Once the
determination as to the amount of zero emission credits to
be paid is made based on the calculations set forth in this
paragraph (2), no subsequent rate impact determinations
shall be made and no adjustments to those contract amounts
shall be allowed. All costs incurred under those contracts
and in implementing this subsection (d-5) shall be
recovered by the electric utility as provided in this
Section.
No later than June 30, 2019, the Commission shall
review the limitation on the amount of zero emission
credits procured under this subsection (d-5) and report to
the General Assembly its findings as to whether that
limitation unduly constrains the procurement of
cost-effective zero emission credits.
(3) Six years after the execution of a contract under
this subsection (d-5), the Agency shall determine whether

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the actual zero emission credit payments received by the
supplier over the 6-year period exceed the Average ZEC
Payment. In addition, at the end of the term of a contract
executed under this subsection (d-5), or at the time, if
any, a zero emission facility's contract is terminated
under subparagraph (E) of paragraph (1) of this subsection
(d-5), then the Agency shall determine whether the actual
zero emission credit payments received by the supplier
over the term of the contract exceed the Average ZEC
Payment, after taking into account any amounts previously
credited back to the utility under this paragraph (3). If
the Agency determines that the actual zero emission credit
payments received by the supplier over the relevant period
exceed the Average ZEC Payment, then the supplier shall
credit the difference back to the utility. The amount of
the credit shall be remitted to the applicable electric
utility no later than 120 days after the Agency's
determination, which the utility shall reflect as a credit
on its retail customer bills as soon as practicable;
however, the credit remitted to the utility shall not
exceed the total amount of payments received by the
facility under its contract.
For purposes of this Section, the Average ZEC Payment
shall be calculated by multiplying the quantity of zero
emission credits delivered under the contract times the
average contract price. The average contract price shall

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be determined by subtracting the amount calculated under
subparagraph (B) of this paragraph (3) from the amount
calculated under subparagraph (A) of this paragraph (3),
as follows:
(A) The average of the Social Cost of Carbon, as
defined in subparagraph (B) of paragraph (1) of this
subsection (d-5), during the term of the contract.
(B) The average of the market price indices, as
defined in subparagraph (B) of paragraph (1) of this
subsection (d-5), during the term of the contract,
minus the baseline market price index, as defined in
subparagraph (B) of paragraph (1) of this subsection
(d-5).
If the subtraction yields a negative number, then the
Average ZEC Payment shall be zero.
(4) Cost-effective zero emission credits procured from
zero emission facilities shall satisfy the applicable
definitions set forth in Section 1-10 of this Act.
(5) The electric utility shall retire all zero
emission credits used to comply with the requirements of
this subsection (d-5).
(6) Electric utilities shall be entitled to recover
all of the costs associated with the procurement of zero
emission credits through an automatic adjustment clause
tariff in accordance with subsection (k) and (m) of
Section 16-108 of the Public Utilities Act, and the

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contracts executed under this subsection (d-5) shall
provide that the utilities' payment obligations under such
contracts shall be reduced if an adjustment is required
under subsection (m) of Section 16-108 of the Public
Utilities Act.
(7) This subsection (d-5) shall become inoperative on
January 1, 2028.
(d-10) Nuclear Plant Assistance; carbon mitigation
credits.
(1) The General Assembly finds:
(A) The health, welfare, and prosperity of all
Illinois citizens require that the State of Illinois act
to avoid and not increase carbon emissions from electric
generation sources while continuing to ensure affordable,
stable, and reliable electricity to all citizens.
(B) Absent immediate action by the State to preserve
existing carbon-free energy resources, those resources may
retire, and the electric generation needs of Illinois'
retail customers may be met instead by facilities that
emit significant amounts of carbon pollution and other
harmful air pollutants at a high social and economic cost
until Illinois is able to develop other forms of clean
energy.
(C) The General Assembly finds that nuclear power
generation is necessary for the State's transition to 100%
clean energy, and ensuring continued operation of nuclear

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plants advances environmental and public health interests
through providing carbon-free electricity while reducing
the air pollution profile of the Illinois energy
generation fleet.
(D) The clean energy attributes of nuclear generation
facilities support the State in its efforts to achieve
100% clean energy.
(E) The State currently invests in various forms of
clean energy, including, but not limited to, renewable
energy, energy efficiency, and low-emission vehicles,
among others.
(F) The Environmental Protection Agency commissioned
an independent audit which provided a detailed assessment
of the financial condition of the Illinois nuclear fleet
to evaluate its financial viability and whether the
environmental benefits of such resources were at risk. The
report identified the risk of losing the environmental
benefits of several specific nuclear units. The report
also identified that the LaSalle County Generating Station
will continue to operate through 2026 and therefore is not
eligible to participate in the carbon mitigation credit
program.
(G) Nuclear plants provide carbon-free energy, which
helps to avoid many health-related negative impacts for
Illinois residents.
(H) The procurement of carbon mitigation credits

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representing the environmental benefits of carbon-free
generation will further the State's efforts at achieving
100% clean energy and decarbonizing the electricity sector
in a safe, reliable, and affordable manner. Further, the
procurement of carbon emission credits will enhance the
health and welfare of Illinois residents through decreased
reliance on more highly polluting generation.
(I) The General Assembly therefore finds it necessary
to establish carbon mitigation credits to ensure decreased
reliance on more carbon-intensive energy resources, for
transitioning to a fully decarbonized electricity sector,
and to help ensure health and welfare of the State's
residents.
(2) As used in this subsection:
"Baseline costs" means costs used to establish a customer
protection cap that have been evaluated through an independent
audit of a carbon-free energy resource conducted by the
Environmental Protection Agency that evaluated projected
annual costs for operation and maintenance expenses; fully
allocated overhead costs, which shall be allocated using the
methodology developed by the Institute for Nuclear Power
Operations; fuel expenditures; nonfuel capital expenditures;
spent fuel expenditures; a return on working capital; the cost
of operational and market risks that could be avoided by
ceasing operation; and any other costs necessary for continued
operations, provided that "necessary" means, for purposes of

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this definition, that the costs could reasonably be avoided
only by ceasing operations of the carbon-free energy resource.
"Carbon mitigation credit" means a tradable credit that
represents the carbon emission reduction attributes of one
megawatt-hour of energy produced from a carbon-free energy
resource.
"Carbon-free energy resource" means a generation facility
that: (1) is fueled by nuclear power; and (2) is
interconnected to PJM Interconnection, LLC.
(3) Procurement.
(A) Beginning with the delivery year commencing on
June 1, 2022, the Agency shall, for electric utilities
serving at least 3,000,000 retail customers in the State,
seek to procure contracts for no more than approximately
54,500,000 cost-effective carbon mitigation credits from
carbon-free energy resources because such credits are
necessary to support current levels of carbon-free energy
generation and ensure the State meets its carbon dioxide
emissions reduction goals. The Agency shall not make a
partial award of a contract for carbon mitigation credits
covering a fractional amount of a carbon-free energy
resource's projected output.
(B) Each carbon-free energy resource that intends to
participate in a procurement shall be required to submit
to the Agency the following information for the resource
on or before the date established by the Agency:

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(i) the in-service date and remaining useful life
of the carbon-free energy resource;
(ii) the amount of power generated annually for
each of the past 10 years, which shall be used to
determine the capability of each facility;
(iii) a commitment to be reflected in any contract
entered into pursuant to this subsection (d-10) to
continue operating the carbon-free energy resource at
a capacity factor of at least 88% annually on average
for the duration of the contract or contracts executed
under the procurement held under this subsection
(d-10), except in an instance described in
subparagraph (E) of paragraph (1) of subsection (d-5)
of this Section or made impracticable as a result of
compliance with law or regulation;
(iv) financial need and the risk of loss of the
environmental benefits of such resource, which shall
include the following information:
(I) the carbon-free energy resource's cost
projections, expressed on a per megawatt-hour
basis, over the next 5 delivery years, which shall
include the following: operation and maintenance
expenses; fully allocated overhead costs, which
shall be allocated using the methodology developed
by the Institute for Nuclear Power Operations;
fuel expenditures; nonfuel capital expenditures;

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spent fuel expenditures; a return on working
capital; the cost of operational and market risks
that could be avoided by ceasing operation; and
any other costs necessary for continued
operations, provided that "necessary" means, for
purposes of this subitem (I), that the costs could
reasonably be avoided only by ceasing operations
of the carbon-free energy resource; and
(II) the carbon-free energy resource's revenue
projections, including energy, capacity, ancillary
services, any other direct State support, known or
anticipated federal attribute credits, known or
anticipated tax credits, and any other direct
federal support.
The information described in this subparagraph (B) may
be submitted on a confidential basis and shall be treated
and maintained by the Agency, the procurement
administrator, and the Commission as confidential and
proprietary and exempt from disclosure under subparagraphs
(a) and (g) of paragraph (1) of Section 7 of the Freedom of
Information Act. The Office of the Attorney General shall
have access to, and maintain the confidentiality of, such
information pursuant to Section 6.5 of the Attorney
General Act.
(C) The Agency shall solicit bids for the contracts
described in this subsection (d-10) from carbon-free

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energy resources that have satisfied the requirements of
subparagraph (B) of this paragraph (3). The contracts
procured pursuant to a procurement event shall reflect,
and be subject to, the following terms, requirements, and
limitations:
(i) Contracts are for delivery of carbon
mitigation credits, and are not energy or capacity
sales contracts requiring physical delivery. Pursuant
to item (iii), contract payments shall fully deduct
the value of any monetized federal production tax
credits, credits issued pursuant to a federal clean
energy standard, and other federal credits if
applicable.
(ii) Contracts for carbon mitigation credits shall
commence with the delivery year beginning on June 1,
2022 and shall be for a term of 5 delivery years
concluding on May 31, 2027.
(iii) The price per carbon mitigation credit to be
paid under a contract for a given delivery year shall
be equal to an accepted bid price less the sum of:
(I) one of the following energy price indices,
selected by the bidder at the time of the bid for
the term of the contract:
(aa) the weighted-average hourly day-ahead
price for the applicable delivery year at the
busbar of all resources procured pursuant to

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this subsection (d-10), weighted by actual
production from the resources; or
(bb) the projected energy price for the
PJM Interconnection, LLC Northern Illinois Hub
for the applicable delivery year determined
according to subitem (aa) of item (iii) of
subparagraph (B) of paragraph (1) of
subsection (d-5).
(II) the Base Residual Auction Capacity Price
for the ComEd zone as determined by PJM
Interconnection, LLC, divided by 24 hours per day,
for the applicable delivery year for the first 3
delivery years, and then any subsequent delivery
years unless the PJM Interconnection, LLC applies
the Minimum Offer Price Rule to participating
carbon-free energy resources because they supply
carbon mitigation credits pursuant to this Section
at which time, upon notice by the carbon-free
energy resource to the Commission and subject to
the Commission's confirmation, the value under
this subitem shall be zero, as further described
in the carbon mitigation credit procurement plan;
and
(III) any value of monetized federal tax
credits, direct payments, or similar subsidy
provided to the carbon-free energy resource from

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any unit of government that is not already
reflected in energy prices.
If the price-per-megawatt-hour calculation
performed under item (iii) of this subparagraph (C)
for a given delivery year results in a net positive
value, then the electric utility counterparty to the
contract shall multiply such net value by the
applicable contract quantity and remit the amount to
the supplier.
To protect retail customers from retail rate
impacts that may arise upon the initiation of carbon
policy changes, if the price-per-megawatt-hour
calculation performed under item (iii) of this
subparagraph (C) for a given delivery year results in
a net negative value, then the supplier counterparty
to the contract shall multiply such net value by the
applicable contract quantity and remit such amount to
the electric utility counterparty. The electric
utility shall reflect such amounts remitted by
suppliers as a credit on its retail customer bills as
soon as practicable.
(iv) To ensure that retail customers in Northern
Illinois do not pay more for carbon mitigation credits
than the value such credits provide, and
notwithstanding the provisions of this subsection
(d-10), the Agency shall not accept bids for contracts

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that exceed a customer protection cap equal to the
baseline costs of carbon-free energy resources.
The baseline costs for the applicable year shall
be the following:
(I) For the delivery year beginning June 1,
2022, the baseline costs shall be an amount equal
to $30.30 per megawatt-hour.
(II) For the delivery year beginning June 1,
2023, the baseline costs shall be an amount equal
to $32.50 per megawatt-hour.
(III) For the delivery year beginning June 1,
2024, the baseline costs shall be an amount equal
to $33.43 per megawatt-hour.
(IV) For the delivery year beginning June 1,
2025, the baseline costs shall be an amount equal
to $33.50 per megawatt-hour.
(V) For the delivery year beginning June 1,
2026, the baseline costs shall be an amount equal
to $34.50 per megawatt-hour.
An Environmental Protection Agency consultant
forecast, included in a report issued April 14, 2021,
projects that a carbon-free energy resource has the
opportunity to earn on average approximately $30.28
per megawatt-hour, for the sale of energy and capacity
during the time period between 2022 and 2027.
Therefore, the sale of carbon mitigation credits

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provides the opportunity to receive an additional
amount per megawatt-hour in addition to the projected
prices for energy and capacity.
Although actual energy and capacity prices may
vary from year-to-year, the General Assembly finds
that this customer protection cap will help ensure
that the cost of carbon mitigation credits will be
less than its value, based upon the social cost of
carbon identified in the Technical Support Document
issued in February 2021 by the U.S. Interagency
Working Group on Social Cost of Greenhouse Gases and
the PJM Interconnection, LLC carbon dioxide marginal
emission rate for 2020, and that a carbon-free energy
resource receiving payment for carbon mitigation
credits receives no more than necessary to keep those
units in operation.
(D) No later than 7 days after the effective date of
this amendatory Act of the 102nd General Assembly, the
Agency shall publish its proposed carbon mitigation credit
procurement plan. The Plan shall provide that winning bids
shall be selected by taking into consideration which
resources best match public interest criteria that
include, but are not limited to, minimizing carbon dioxide
emissions that result from electricity consumed in
Illinois and minimizing sulfur dioxide, nitrogen oxide,
and particulate matter emissions that adversely affect the

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citizens of this State. The selection of winning bids
shall also take into account the incremental environmental
benefits resulting from the procurement or procurements,
such as any existing environmental benefits that are
preserved by a procurement held under this subsection
(d-10) and would cease to exist if the procurement were
not held, including the preservation of carbon-free energy
resources. For those bidders having the same public
interest criteria score, the relative ranking of such
bidders shall be determined by price. The Plan shall
describe in detail how each public interest factor shall
be considered and weighted in the bid selection process to
ensure that the public interest criteria are applied to
the procurement. The Plan shall, to the extent practical
and permissible by federal law, ensure that successful
bidders make commercially reasonable efforts to apply for
federal tax credits, direct payments, or similar subsidy
programs that support carbon-free generation and for which
the successful bidder is eligible. Upon publishing of the
carbon mitigation credit procurement plan, copies of the
plan shall be posted and made publicly available on the
Agency's website. All interested parties shall have 7 days
following the date of posting to provide comment to the
Agency on the plan. All comments shall be posted to the
Agency's website. Following the end of the comment period,
but no more than 19 days later than the effective date of

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this amendatory Act of the 102nd General Assembly, the
Agency shall revise the plan as necessary based on the
comments received and file its carbon mitigation credit
procurement plan with the Commission.
(E) If the Commission determines that the plan is
likely to result in the procurement of cost-effective
carbon mitigation credits, then the Commission shall,
after notice and hearing and opportunity for comment, but
no later than 42 days after the Agency filed the plan,
approve the plan or approve it with modification. For
purposes of this subsection (d-10), "cost-effective" means
carbon mitigation credits that are procured from
carbon-free energy resources at prices that are within the
limits specified in this paragraph (3). As part of the
Commission's review and acceptance or rejection of the
procurement results, the Commission shall, in its public
notice of successful bidders:
(i) identify how the selected carbon-free energy
resources satisfy the public interest criteria
described in this paragraph (3) of minimizing carbon
dioxide emissions that result from electricity
consumed in Illinois and minimizing sulfur dioxide,
nitrogen oxide, and particulate matter emissions that
adversely affect the citizens of this State;
(ii) specifically address how the selection of
carbon-free energy resources takes into account the

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incremental environmental benefits resulting from the
procurement, including any existing environmental
benefits that are preserved by the procurements held
under this amendatory Act of the 102nd General
Assembly and would have ceased to exist if the
procurements had not been held, such as the
preservation of carbon-free energy resources;
(iii) quantify the environmental benefit of
preserving the carbon-free energy resources procured
pursuant to this subsection (d-10), including the
following:
(I) an assessment value of avoided greenhouse
gas emissions measured as the product of the
carbon-free energy resources' output over the
contract term, using generally accepted
methodologies for the valuation of avoided
emissions; and
(II) an assessment of costs of replacement
with other carbon-free energy resources and
renewable energy resources, including wind and
photovoltaic generation, based upon an assessment
of the prices paid for renewable energy credits
through programs and procurements conducted
pursuant to subsection (c) of Section 1-75 of this
Act, and the additional storage necessary to
produce the same or similar capability of matching

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customer usage patterns.
(F) The procurements described in this paragraph (3),
including, but not limited to, the execution of all
contracts procured, shall be completed no later than
December 3, 2021. The procurement and plan approval
processes required by this paragraph (3) shall be
conducted in conjunction with the procurement and plan
approval processes required by Section 16-111.5 of the
Public Utilities Act, to the extent practicable. However,
the Agency and Commission may, as appropriate, modify the
various dates and timelines under this subparagraph and
subparagraphs (D) and (E) of this paragraph (3) to meet
the December 3, 2021 contract execution deadline.
Following the completion of such procurements, and
consistent with this paragraph (3), the Agency shall
calculate the payments to be made under each contract in a
timely fashion.
(F-1) Costs incurred by the electric utility pursuant
to a contract authorized by this subsection (d-10) shall
be deemed prudently incurred and reasonable in amount, and
the electric utility shall be entitled to full cost
recovery pursuant to a tariff or tariffs filed with the
Commission.
(G) The counterparty electric utility shall retire all
carbon mitigation credits used to comply with the
requirements of this subsection (d-10).

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(H) If a carbon-free energy resource is sold to
another owner, the rights, obligations, and commitments
under this subsection (d-10) shall continue to the
subsequent owner.
(I) This subsection (d-10) shall become inoperative on
January 1, 2028.
(d-20) Energy storage system portfolio standard.
(1) The General Assembly finds that the deployment of
energy storage systems is necessary to successfully
integrate high levels of renewable energy, to avoid the
creation and increase of carbon emissions from electric
generation sources, and to ensure affordable, stable,
clean, reliable, and resilient electricity.
(2) The Agency shall develop an energy storage system
resources procurement plan that includes the competitive
procurement events, procurement programs, or both, as
necessary (i) to meet the goals set forth in this
subsection (d-20), (ii) to meet the planning requirements
established under Sections 16-201 and 16-202 of the Public
Utilities Act, (iii) to meet the clean energy policy
established by Public Act 102-662, and (iv) to cause
electric utilities serving more than 300,000 customers in
the State as of January 1, 2019 to contract for energy
storage resources. The energy storage system resources
procurement plan approval processes shall be conducted
consistent with the processes outlined in paragraph (6) of

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subsection (b) of Section 16-111.5 of the Public Utilities
Act, with the initial energy storage system resources
procurement plan released for comment in calendar year
2027. The Agency shall review and may revise the energy
storage system resources procurement plan at least every 2
years. The Agency shall establish, and the Commission
shall approve or approve as modified, an energy storage
system resources procurement plan that includes:
(A) storage targets in addition to the initial
procurements specified in paragraph (3) of this
subsection (d-20) at levels identified through the
integrated resource planning process outlined in
Section 16-202 of the Public Utilities Act;
(B) a bid selection process that is based on the
bid price, when compared with an equal energy storage
duration and interconnected to the same independent
system operator (ISO) or regional transmission
organization (RTO), and that may provide for
consideration of the following:
(i) the project's viability and ability to
meet or exceed operational date targets;
(ii) the developer's experience;
(iii) requirements for demonstration of
binding site control that are sufficient for
proposed energy storage facilities;
(iv) the availability or dependence on any

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transmission expansion or upgrades needed; and
(v) other resource adequacy and reliability
considerations;
(C) consideration of the need to ensure adequate,
reliable, affordable, efficient, and environmentally
sustainable electric service at the lowest total cost
over time;
(D) proposals for the financial support of energy
storage systems using contract models, which may
include, but are not limited to, the following:
(i) an indexed storage credit procurement,
including payments to energy storage system owners
or operators with any offsets and refunds for
potential energy and capacity revenues;
(ii) support for energy storage system
resources through contract structures that do not
create contractual obligations on utilities that
are not contingent on full and timely cost
recovery, that avoid negative financial impacts on
the utilities, and that are agreed upon by the
utilities; and
(iii) other approaches as deemed suitable by
the Agency and the Commission; and
(E) consideration that the Agency may include a
methodology that could prioritize procurement of
energy storage resources that are located in

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communities eligible to receive Energy Transition
Community Grants pursuant to Section 10-20 of the
Energy Community Reinvestment Act.
In developing its procurement plan and conducting the
storage procurements outlined in this paragraph (2) and in
paragraph (3), the Agency may use the services of expert
consulting firms identified in paragraphs (1) and (2) of
subsection (a) of this Section.
(3) Notwithstanding whether an energy storage system
resources procurement plan has been approved, the
following provisions shall apply to the Agency's initial
procurement of energy storage system resources under this
subsection (d-20):
(A) The Agency shall conduct an initial energy
storage procurement on or before August 26, 2026 or 90
days after the effective date of this amendatory Act
of the 104th General Assembly, whichever is earlier.
For the purposes of this initial energy storage
procurement, the Agency shall conduct a procurement
that results in electric utilities that served more
than 300,000 customers in the State as of January 1,
2019 contracting for at least 1,038 megawatts of
cost-effective stand-alone energy storage systems that
can achieve commercial operation on or before December
31, 2029 or an alternative date proposed by the Agency
that is no later than December 31, 2030. The

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procurement target shall be separated for projects
interconnected within Midcontinent Independent System
Operator Local Resource Zone 4 (MISO Zone 4) and for
projects interconnected within the PJM
Interconnection, LLC ComEd Locational Deliverability
Area (PJM ComEd Area) as follows:
(i) 450 megawatts in MISO Zone 4; and
(ii) 588 megawatts in the PJM ComEd Area.
For purposes of this subsection (d-20),
"stand-alone" means systems that are (i) separately
metered by a revenue-quality meter that satisfies the
requirements of the RTO; (ii) operate independently
without constraints or hindrances from other
generation units; and (iii) demonstrate the ability to
charge and discharge independent of any generation
unit output.
(B) The Agency shall conduct a series of
additional energy storage procurements that result in
electric utilities contracting for energy storage
resources in an amount of 3,000 megawatts of
cumulative energy storage capacity for projects
committed to reaching commercial operation on or
before December 31, 2030, or an alternative date
proposed by the Agency, subject to extension for a
delay due to interconnection of the energy storage
system, a delay in obtaining permits necessary to

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build or operate the energy storage system, or other
circumstances at the discretion of the Agency.
The additional energy storage resources
procurements shall be conducted in calendar years 2027
and 2028 in a manner that ensures the quantities
listed in this subparagraph (B), and as updated in the
integrated resource plan approved by the Commission
pursuant to Section 16-201 of the Public Utilities
Act, are met in the specified timeframe. To the extent
the integrated resource planning process outlined in
Section 16-202 of the Public Utilities Act authorizes
energy storage system procurement amounts above the
amount identified in this subparagraph (B), the Agency
shall conduct additional energy storage procurements
in 2028, 2029, 2030, and thereafter that result in
electric utilities contracting for energy storage
resources at those additional identified levels. The
procurements shall be conducted in a manner that
maximizes projects available in the MISO and PJM
queues, ensures the likelihood of project development
through the development of project maturity
requirements, enables sufficient competition for price
competitiveness, and aligns to the extent practicable
with regional transmission organization study phases.
The procurements shall select projects interconnected
to MISO Zone 4 and the PJM ComEd Area and shall follow

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either (i) a similar geographic split to the ratio of
quantities established in subparagraph (A) of this
paragraph (3), (ii) an alternative geographic split
proposed by the Agency based on project availability
in advanced stages of the MISO and PJM queues, or (iii)
that is informed by MISO and PJM planning activities,
auctions, or reports that indicate capacity resource
shortages or impending shortages and that reflect the
assessments made through the processes outlined in
subparagraph (A) of paragraph (2). The additional
energy storage capacity procurements may be adjusted
upward if determined necessary through the planning
process outlined in Section 16-201 of the Public
Utilities Act at times determined by the Commission.
(C) The initial energy storage resources
procurement under subparagraph (A) of this paragraph
(3) shall adopt a standard indexed storage credit
contract modeled after the contract and follow a
process modeled after the process included in the
staff report submitted to the Governor, General
Assembly, and Commission pursuant to subsection (g) of
Section 16-135 of the Public Utilities Act on May 1,
2025. In developing the procurement rules and
procurement process for the initial procurement, the
Agency shall provide an opportunity for comment on the
indexed storage credit contract included in the May 1,

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2025 staff report and shall adopt modifications to the
contract consistent with the process outlined in
paragraph (2) of subsection (e) of Section 16-111.5 of
the Public Utilities Act.
(D) For the additional energy storage resources
procurements conducted in accordance with subparagraph
(B) of this paragraph (3), the Agency may, among other
considerations, consider other contract structures if
such contract structures and agreements do not create
contractual obligations on utilities that are not
contingent on full and timely cost recovery, avoid
negative financial impacts on the utilities, and are
agreed upon by the participating utility.
(E) The initial and additional energy storage
resources procurements under this paragraph (3) shall
solicit 20-year contracts.
(F) The Agency shall submit its proposed selection
of successful bids for each procurement event pursuant
to paragraphs (2) and (3) to the Commission for
approval consistent with the processes outlined in
Section 16-111.5 of the Public Utilities Act to the
extent practicable.
(4) The energy storage system resources procurement
plans developed by the Agency may consider alternatives to
the initial and additional procurement terms described in
paragraph (3) of this subsection (d-20), including, but

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not limited to:
(A) alternatives to the standard indexed storage
credit contract used in the initial terms described in
subparagraph (C) of paragraph (3) of this subsection
(d-20);
(B) energy storage systems that are not
stand-alone;
(C) proportionate allocations between MISO Zone 4
and the PJM ComEd Area that are not based upon load
share, including allocations reflecting the
assessments made through the processes outlined in
subparagraph (A) of paragraph (2);
(D) contract lengths other than 20 years;
(E) energy storage system durations other than 4
hours; and
(F) energy storage systems connected to the
distribution systems of the electric utilities.
The Agency may propose specific timelines for energy
storage system resources procurements, which may differ
across RTO zones, that are based in part upon a
consideration of (i) the timing of the release of
interconnection cost information through both MISO and PJM
interconnection queue processes, (ii) factors that
maximize the likelihood of successful project development,
(iii) enabling sufficient competition for price
competitiveness, and (iv) aligning to the extent

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practicable with RTO study phases.
(5) The Agency shall procure cost-effective energy
storage credits or other contract instruments intended to
facilitate the successful development of energy storage
projects. The procurement administrator shall establish
confidential price benchmarks based on publicly available
data on regional technology costs. Confidential price
benchmarks shall be developed by the procurement
administrator, in consultation with Commission staff,
Agency staff, and the procurement monitor, and shall be
subject to Commission review and approval. Price
benchmarks shall reflect development costs, financing
costs, and related costs resulting from requirements
imposed through other provisions of State law. As used in
this paragraph (5), "cost-effective" means a bidder's bid
price that does not exceed confidential price benchmarks.
(6) All procurements under this subsection (d-20)
shall comply with the geographic requirements in
subparagraph (I) of paragraph (1) of subsection (c) of
Section 1-75 and shall follow the procurement processes
and procedures described in this Section and Section
16-111.5 of the Public Utilities Act, to the extent
practicable. The processes and procedures may be expedited
to accommodate the schedule established by this Section.
The Agency shall require all bidders to pay to the Agency a
nonrefundable deposit determined by the Agency and no less

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than $10,000 per bid as practical. The Agency may also
assess bidder and supplier fees to cover the cost of
procurement events and develop collateral requirements to
maximize the likelihood of successful project development.
Bidders in the initial and additional procurements
described in paragraph (3) of this subsection (d-20) shall
also demonstrate experience in developing to commercial
readiness. As used in this paragraph (6), "developing to
commercial readiness" means having notice to proceed in
owning or operating energy facilities with a combined
nameplate capacity of at least 100 megawatts.
(7) In order to advance priority access to the clean
energy economy for businesses and workers from communities
that have been excluded from economic opportunities in the
energy sector, have been subject to disproportionate
levels of pollution, and have disproportionately
experienced negative public health outcomes, the Agency
shall apply its equity accountability system and minimum
equity standards established under subsections (c-10),
(c-15), (c-20), (c-25), and (c-30) of this Section to
energy storage procurement and programs and may include
any proposed modifications to the equity accountability
system and minimum equity standards that may be warranted
with respect to energy storage resources in its plan
submission to the Commission under Section 16-111.5 of the
Public Utilities Act.

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(8) Projects shall be developed in compliance with the
prevailing wage and project labor agreement requirements
for renewable energy projects in subparagraph (Q) of
paragraph (1) of subsection (c) of Section 1-75.
(9) An entity operating an energy storage facility
shall demonstrate that it has entered into a labor peace
agreement with a bona fide labor organization that is
actively engaged in representing its employees. The labor
peace agreement shall apply to the employees necessary for
the ongoing maintenance and operation of the energy
storage facility. The existence of a labor peace agreement
shall be an ongoing material condition of an entity's
authorization to maintain and operate the energy storage
facility.
(10) In order to promote the competitive development
of energy storage systems in furtherance of the State's
interest in the health, safety, and welfare of its
residents, storage credits shall not be eligible to be
selected under this subsection (d-20) if the energy
storage resources are sourced from an energy storage
system whose costs were being recovered through rates
regulated by the State or any other state or states on or
after January 1, 2017. No entity shall be permitted to bid
unless it certifies to the Agency that it is not an
electric utility, as defined in Section 16-102 of the
Public Utilities Act, serving more than 10,000 customers

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in the State.
(11) The Agency shall require, as a prerequisite to
payment for any storage credits, that the winning bidder
provide the Agency or its designee a copy of the
interconnection agreement under which the applicable
energy storage system is connected to the transmission or
distribution system.
(12) Contracts shall provide that, if the cost
recovery mechanism referenced in subsection (k) of Section
16-108 of the Public Utilities Act remains in full force
without amendment or the utility is otherwise authorized
or entitled to full, prompt, and uninterrupted recovery of
its costs through any other mechanism, then such seller
shall be entitled to full, prompt, and uninterrupted
payment under the applicable contract notwithstanding the
application of this paragraph (12).
(e) The draft procurement plans are subject to public
comment, as required by Section 16-111.5 of the Public
Utilities Act.
(f) The Agency shall submit the final procurement plan to
the Commission. The Agency shall revise a procurement plan if
the Commission determines that it does not meet the standards
set forth in Section 16-111.5 of the Public Utilities Act.
(g) The Agency shall assess fees to each affected utility
to recover the costs incurred in preparation of procurement
plans and in the operation of programs.

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(h) The Agency shall assess fees to each bidder to recover
the costs incurred in connection with a competitive
procurement process.
(i) A renewable energy credit, carbon emission credit,
zero emission credit, or carbon mitigation credit can only be
used once to comply with a single portfolio or other standard
as set forth in subsection (c), subsection (d), or subsection
(d-5) of this Section, respectively. A renewable energy
credit, carbon emission credit, zero emission credit, or
carbon mitigation credit cannot be used to satisfy the
requirements of more than one standard. If more than one type
of credit is issued for the same megawatt hour of energy, only
one credit can be used to satisfy the requirements of a single
standard. After such use, the credit must be retired together
with any other credits issued for the same megawatt hour of
energy.
(Source: P.A. 103-380, eff. 1-1-24; 103-580, eff. 12-8-23;
103-1066, eff. 2-20-25; 104-458, eff. 6-1-26.)
Section 25. The Public Utilities Act is amended by
changing Sections 8-103B, 16-107.5, 16-107.6, 16-107.9,
16-202, 20-140, and 23-115 as follows:
(220 ILCS 5/8-103B)
(Text of Section before amendment by P.A. 104-458)
Sec. 8-103B. Energy efficiency and demand-response

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measures.
(a) It is the policy of the State that electric utilities
are required to use cost-effective energy efficiency and
demand-response measures to reduce delivery load. Requiring
investment in cost-effective energy efficiency and
demand-response measures will reduce direct and indirect costs
to consumers by decreasing environmental impacts and by
avoiding or delaying the need for new generation,
transmission, and distribution infrastructure. It serves the
public interest to allow electric utilities to recover costs
for reasonably and prudently incurred expenditures for energy
efficiency and demand-response measures. As used in this
Section, "cost-effective" means that the measures satisfy the
total resource cost test. The low-income measures described in
subsection (c) of this Section shall not be required to meet
the total resource cost test. For purposes of this Section,
the terms "energy-efficiency", "demand-response", "electric
utility", and "total resource cost test" have the meanings set
forth in the Illinois Power Agency Act. "Black, indigenous,
and people of color" and "BIPOC" means people who are members
of the groups described in subparagraphs (a) through (e) of
paragraph (A) of subsection (1) of Section 2 of the Business
Enterprise for Minorities, Women, and Persons with
Disabilities Act.
(a-5) This Section applies to electric utilities serving
more than 500,000 retail customers in the State for those

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multi-year plans commencing after December 31, 2017.
(b) For purposes of this Section, electric utilities
subject to this Section that serve more than 3,000,000 retail
customers in the State shall be deemed to have achieved a
cumulative persisting annual savings of 6.6% from energy
efficiency measures and programs implemented during the period
beginning January 1, 2012 and ending December 31, 2017, which
percent is based on the deemed average weather normalized
sales of electric power and energy during calendar years 2014,
2015, and 2016 of 88,000,000 MWhs. For the purposes of this
subsection (b) and subsection (b-5), the 88,000,000 MWhs of
deemed electric power and energy sales shall be reduced by the
number of MWhs equal to the sum of the annual consumption of
customers that have opted out of subsections (a) through (j)
of this Section under paragraph (1) of subsection (l) of this
Section, as averaged across the calendar years 2014, 2015, and
2016. After 2017, the deemed value of cumulative persisting
annual savings from energy efficiency measures and programs
implemented during the period beginning January 1, 2012 and
ending December 31, 2017, shall be reduced each year, as
follows, and the applicable value shall be applied to and
count toward the utility's achievement of the cumulative
persisting annual savings goals set forth in subsection (b-5):
(1) 5.8% deemed cumulative persisting annual savings
for the year ending December 31, 2018;
(2) 5.2% deemed cumulative persisting annual savings

10400HB1700sam002 - 445 - LRB104 08228 AAS 38463 a
for the year ending December 31, 2019;
(3) 4.5% deemed cumulative persisting annual savings
for the year ending December 31, 2020;
(4) 4.0% deemed cumulative persisting annual savings
for the year ending December 31, 2021;
(5) 3.5% deemed cumulative persisting annual savings
for the year ending December 31, 2022;
(6) 3.1% deemed cumulative persisting annual savings
for the year ending December 31, 2023;
(7) 2.8% deemed cumulative persisting annual savings
for the year ending December 31, 2024;
(8) 2.5% deemed cumulative persisting annual savings
for the year ending December 31, 2025;
(9) 2.3% deemed cumulative persisting annual savings
for the year ending December 31, 2026;
(10) 2.1% deemed cumulative persisting annual savings
for the year ending December 31, 2027;
(11) 1.8% deemed cumulative persisting annual savings
for the year ending December 31, 2028;
(12) 1.7% deemed cumulative persisting annual savings
for the year ending December 31, 2029;
(13) 1.5% deemed cumulative persisting annual savings
for the year ending December 31, 2030;
(14) 1.3% deemed cumulative persisting annual savings
for the year ending December 31, 2031;
(15) 1.1% deemed cumulative persisting annual savings

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for the year ending December 31, 2032;
(16) 0.9% deemed cumulative persisting annual savings
for the year ending December 31, 2033;
(17) 0.7% deemed cumulative persisting annual savings
for the year ending December 31, 2034;
(18) 0.5% deemed cumulative persisting annual savings
for the year ending December 31, 2035;
(19) 0.4% deemed cumulative persisting annual savings
for the year ending December 31, 2036;
(20) 0.3% deemed cumulative persisting annual savings
for the year ending December 31, 2037;
(21) 0.2% deemed cumulative persisting annual savings
for the year ending December 31, 2038;
(22) 0.1% deemed cumulative persisting annual savings
for the year ending December 31, 2039; and
(23) 0.0% deemed cumulative persisting annual savings
for the year ending December 31, 2040 and all subsequent
years.
For purposes of this Section, "cumulative persisting
annual savings" means the total electric energy savings in a
given year from measures installed in that year or in previous
years, but no earlier than January 1, 2012, that are still
operational and providing savings in that year because the
measures have not yet reached the end of their useful lives.
(b-5) Beginning in 2018, electric utilities subject to
this Section that serve more than 3,000,000 retail customers

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in the State shall achieve the following cumulative persisting
annual savings goals, as modified by subsection (f) of this
Section and as compared to the deemed baseline of 88,000,000
MWhs of electric power and energy sales set forth in
subsection (b), as reduced by the number of MWhs equal to the
sum of the annual consumption of customers that have opted out
of subsections (a) through (j) of this Section under paragraph
(1) of subsection (l) of this Section as averaged across the
calendar years 2014, 2015, and 2016, through the
implementation of energy efficiency measures during the
applicable year and in prior years, but no earlier than
January 1, 2012:
(1) 7.8% cumulative persisting annual savings for the
year ending December 31, 2018;
(2) 9.1% cumulative persisting annual savings for the
year ending December 31, 2019;
(3) 10.4% cumulative persisting annual savings for the
year ending December 31, 2020;
(4) 11.8% cumulative persisting annual savings for the
year ending December 31, 2021;
(5) 13.1% cumulative persisting annual savings for the
year ending December 31, 2022;
(6) 14.4% cumulative persisting annual savings for the
year ending December 31, 2023;
(7) 15.7% cumulative persisting annual savings for the
year ending December 31, 2024;

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(8) 17% cumulative persisting annual savings for the
year ending December 31, 2025;
(9) 17.9% cumulative persisting annual savings for the
year ending December 31, 2026;
(10) 18.8% cumulative persisting annual savings for
the year ending December 31, 2027;
(11) 19.7% cumulative persisting annual savings for
the year ending December 31, 2028;
(12) 20.6% cumulative persisting annual savings for
the year ending December 31, 2029; and
(13) 21.5% cumulative persisting annual savings for
the year ending December 31, 2030.
No later than December 31, 2021, the Illinois Commerce
Commission shall establish additional cumulative persisting
annual savings goals for the years 2031 through 2035. No later
than December 31, 2024, the Illinois Commerce Commission shall
establish additional cumulative persisting annual savings
goals for the years 2036 through 2040. The Commission shall
also establish additional cumulative persisting annual savings
goals every 5 years thereafter to ensure that utilities always
have goals that extend at least 11 years into the future. The
cumulative persisting annual savings goals beyond the year
2030 shall increase by 0.9 percentage points per year, absent
a Commission decision to initiate a proceeding to consider
establishing goals that increase by more or less than that
amount. Such a proceeding must be conducted in accordance with

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the procedures described in subsection (f) of this Section. If
such a proceeding is initiated, the cumulative persisting
annual savings goals established by the Commission through
that proceeding shall reflect the Commission's best estimate
of the maximum amount of additional savings that are forecast
to be cost-effectively achievable unless such best estimates
would result in goals that represent less than 0.5 percentage
point annual increases in total cumulative persisting annual
savings. The Commission may only establish goals that
represent less than 0.5 percentage point annual increases in
cumulative persisting annual savings if it can demonstrate,
based on clear and convincing evidence and through independent
analysis, that 0.5 percentage point increases are not
cost-effectively achievable. The Commission shall inform its
decision based on an energy efficiency potential study that
conforms to the requirements of this Section.
(b-10) For purposes of this Section, electric utilities
subject to this Section that serve less than 3,000,000 retail
customers but more than 500,000 retail customers in the State
shall be deemed to have achieved a cumulative persisting
annual savings of 6.6% from energy efficiency measures and
programs implemented during the period beginning January 1,
2012 and ending December 31, 2017, which is based on the deemed
average weather normalized sales of electric power and energy
during calendar years 2014, 2015, and 2016 of 36,900,000 MWhs.
For the purposes of this subsection (b-10) and subsection

10400HB1700sam002 - 450 - LRB104 08228 AAS 38463 a
(b-15), the 36,900,000 MWhs of deemed electric power and
energy sales shall be reduced by the number of MWhs equal to
the sum of the annual consumption of customers that have opted
out of subsections (a) through (j) of this Section under
paragraph (1) of subsection (l) of this Section, as averaged
across the calendar years 2014, 2015, and 2016. After 2017,
the deemed value of cumulative persisting annual savings from
energy efficiency measures and programs implemented during the
period beginning January 1, 2012 and ending December 31, 2017,
shall be reduced each year, as follows, and the applicable
value shall be applied to and count toward the utility's
achievement of the cumulative persisting annual savings goals
set forth in subsection (b-15):
(1) 5.8% deemed cumulative persisting annual savings
for the year ending December 31, 2018;
(2) 5.2% deemed cumulative persisting annual savings
for the year ending December 31, 2019;
(3) 4.5% deemed cumulative persisting annual savings
for the year ending December 31, 2020;
(4) 4.0% deemed cumulative persisting annual savings
for the year ending December 31, 2021;
(5) 3.5% deemed cumulative persisting annual savings
for the year ending December 31, 2022;
(6) 3.1% deemed cumulative persisting annual savings
for the year ending December 31, 2023;
(7) 2.8% deemed cumulative persisting annual savings

10400HB1700sam002 - 451 - LRB104 08228 AAS 38463 a
for the year ending December 31, 2024;
(8) 2.5% deemed cumulative persisting annual savings
for the year ending December 31, 2025;
(9) 2.3% deemed cumulative persisting annual savings
for the year ending December 31, 2026;
(10) 2.1% deemed cumulative persisting annual savings
for the year ending December 31, 2027;
(11) 1.8% deemed cumulative persisting annual savings
for the year ending December 31, 2028;
(12) 1.7% deemed cumulative persisting annual savings
for the year ending December 31, 2029;
(13) 1.5% deemed cumulative persisting annual savings
for the year ending December 31, 2030;
(14) 1.3% deemed cumulative persisting annual savings
for the year ending December 31, 2031;
(15) 1.1% deemed cumulative persisting annual savings
for the year ending December 31, 2032;
(16) 0.9% deemed cumulative persisting annual savings
for the year ending December 31, 2033;
(17) 0.7% deemed cumulative persisting annual savings
for the year ending December 31, 2034;
(18) 0.5% deemed cumulative persisting annual savings
for the year ending December 31, 2035;
(19) 0.4% deemed cumulative persisting annual savings
for the year ending December 31, 2036;
(20) 0.3% deemed cumulative persisting annual savings

10400HB1700sam002 - 452 - LRB104 08228 AAS 38463 a
for the year ending December 31, 2037;
(21) 0.2% deemed cumulative persisting annual savings
for the year ending December 31, 2038;
(22) 0.1% deemed cumulative persisting annual savings
for the year ending December 31, 2039; and
(23) 0.0% deemed cumulative persisting annual savings
for the year ending December 31, 2040 and all subsequent
years.
(b-15) Beginning in 2018, electric utilities subject to
this Section that serve less than 3,000,000 retail customers
but more than 500,000 retail customers in the State shall
achieve the following cumulative persisting annual savings
goals, as modified by subsection (b-20) and subsection (f) of
this Section and as compared to the deemed baseline as reduced
by the number of MWhs equal to the sum of the annual
consumption of customers that have opted out of subsections
(a) through (j) of this Section under paragraph (1) of
subsection (l) of this Section as averaged across the calendar
years 2014, 2015, and 2016, through the implementation of
energy efficiency measures during the applicable year and in
prior years, but no earlier than January 1, 2012:
(1) 7.4% cumulative persisting annual savings for the
year ending December 31, 2018;
(2) 8.2% cumulative persisting annual savings for the
year ending December 31, 2019;
(3) 9.0% cumulative persisting annual savings for the

10400HB1700sam002 - 453 - LRB104 08228 AAS 38463 a
year ending December 31, 2020;
(4) 9.8% cumulative persisting annual savings for the
year ending December 31, 2021;
(5) 10.6% cumulative persisting annual savings for the
year ending December 31, 2022;
(6) 11.4% cumulative persisting annual savings for the
year ending December 31, 2023;
(7) 12.2% cumulative persisting annual savings for the
year ending December 31, 2024;
(8) 13% cumulative persisting annual savings for the
year ending December 31, 2025;
(9) 13.6% cumulative persisting annual savings for the
year ending December 31, 2026;
(10) 14.2% cumulative persisting annual savings for
the year ending December 31, 2027;
(11) 14.8% cumulative persisting annual savings for
the year ending December 31, 2028;
(12) 15.4% cumulative persisting annual savings for
the year ending December 31, 2029; and
(13) 16% cumulative persisting annual savings for the
year ending December 31, 2030.
No later than December 31, 2021, the Illinois Commerce
Commission shall establish additional cumulative persisting
annual savings goals for the years 2031 through 2035. No later
than December 31, 2024, the Illinois Commerce Commission shall
establish additional cumulative persisting annual savings

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goals for the years 2036 through 2040. The Commission shall
also establish additional cumulative persisting annual savings
goals every 5 years thereafter to ensure that utilities always
have goals that extend at least 11 years into the future. The
cumulative persisting annual savings goals beyond the year
2030 shall increase by 0.6 percentage points per year, absent
a Commission decision to initiate a proceeding to consider
establishing goals that increase by more or less than that
amount. Such a proceeding must be conducted in accordance with
the procedures described in subsection (f) of this Section. If
such a proceeding is initiated, the cumulative persisting
annual savings goals established by the Commission through
that proceeding shall reflect the Commission's best estimate
of the maximum amount of additional savings that are forecast
to be cost-effectively achievable unless such best estimates
would result in goals that represent less than 0.4 percentage
point annual increases in total cumulative persisting annual
savings. The Commission may only establish goals that
represent less than 0.4 percentage point annual increases in
cumulative persisting annual savings if it can demonstrate,
based on clear and convincing evidence and through independent
analysis, that 0.4 percentage point increases are not
cost-effectively achievable. The Commission shall inform its
decision based on an energy efficiency potential study that
conforms to the requirements of this Section.
(b-20) Each electric utility subject to this Section may

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

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

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gas utility discontinues funding the program. In that event,
the energy savings value associated with such other fuels
shall be converted to electric energy savings on an equivalent
Btu basis for the premises. However, the electric utility
shall prioritize programs for low-income residential customers
to the extent practicable. An electric utility may recover the
costs of offering the gas energy efficiency measures under
this subsection (b-25).
For those energy efficiency measures or programs that save
both electricity and other fuels but are not jointly offered
with a gas utility under plans approved under this Section and
Section 8-104 or not offered with an affiliated gas utility
under paragraph (6) of subsection (f) of Section 8-104 of this
Act, the electric utility may count savings of fuels other
than electricity toward the achievement of its annual savings
goal, and the energy savings value associated with such other
fuels shall be converted to electric energy savings on an
equivalent Btu basis at the premises.
In no event shall more than 10% of each year's applicable
annual total savings requirement as defined in paragraph (7.5)
of subsection (g) of this Section be met through savings of
fuels other than electricity.
(b-27) Beginning in 2022, an electric utility may offer
and promote measures that electrify space heating, water
heating, cooling, drying, cooking, industrial processes, and
other building and industrial end uses that would otherwise be

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served by combustion of fossil fuel at the premises, provided
that the electrification measures reduce total energy
consumption at the premises. The electric utility may count
the reduction in energy consumption at the premises toward
achievement of its annual savings goals. The reduction in
energy consumption at the premises shall be calculated as the
difference between: (A) the reduction in Btu consumption of
fossil fuels as a result of electrification, converted to
kilowatt-hour equivalents by dividing by 3,412 Btus per
kilowatt hour; and (B) the increase in kilowatt hours of
electricity consumption resulting from the displacement of
fossil fuel consumption as a result of electrification. An
electric utility may recover the costs of offering and
promoting electrification measures under this subsection
(b-27).
In no event shall electrification savings counted toward
each year's applicable annual total savings requirement, as
defined in paragraph (7.5) of subsection (g) of this Section,
be greater than:
(1) 5% per year for each year from 2022 through 2025;
(2) 10% per year for each year from 2026 through 2029;
and
(3) 15% per year for 2030 and all subsequent years.
In addition, a minimum of 25% of all electrification savings
counted toward a utility's applicable annual total savings
requirement must be from electrification of end uses in

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low-income housing. The limitations on electrification savings
that may be counted toward a utility's annual savings goals
are separate from and in addition to the subsection (b-25)
limitations governing the counting of the other fuel savings
resulting from efficiency measures and programs.
As part of the annual informational filing to the
Commission that is required under paragraph (9) of subsection
(g) of this Section, each utility shall identify the specific
electrification measures offered under this subsection (b-27);
the quantity of each electrification measure that was
installed by its customers; the average total cost, average
utility cost, average reduction in fossil fuel consumption,
and average increase in electricity consumption associated
with each electrification measure; the portion of
installations of each electrification measure that were in
low-income single-family housing, low-income multifamily
housing, non-low-income single-family housing, non-low-income
multifamily housing, commercial buildings, and industrial
facilities; and the quantity of savings associated with each
measure category in each customer category that are being
counted toward the utility's applicable annual total savings
requirement. Prior to installing an electrification measure,
the utility shall provide a customer with an estimate of the
impact of the new measure on the customer's average monthly
electric bill and total annual energy expenses.
(c) Electric utilities shall be responsible for overseeing

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the design, development, and filing of energy efficiency plans
with the Commission and may, as part of that implementation,
outsource various aspects of program development and
implementation. A minimum of 10%, for electric utilities that
serve more than 3,000,000 retail customers in the State, and a
minimum of 7%, for electric utilities that serve less than
3,000,000 retail customers but more than 500,000 retail
customers in the State, of the utility's entire portfolio
funding level for a given year shall be used to procure
cost-effective energy efficiency measures from units of local
government, municipal corporations, school districts, public
housing, public institutions of higher education, and
community college districts, provided that a minimum
percentage of available funds shall be used to procure energy
efficiency from public housing, which percentage shall be
equal to public housing's share of public building energy
consumption.
The utilities shall also implement energy efficiency
measures targeted at low-income households, which, for
purposes of this Section, shall be defined as households at or
below 80% of area median income, and expenditures to implement
the measures shall be no less than $40,000,000 per year for
electric utilities that serve more than 3,000,000 retail
customers in the State and no less than $13,000,000 per year
for electric utilities that serve less than 3,000,000 retail
customers but more than 500,000 retail customers in the State.

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The ratio of spending on efficiency programs targeted at
low-income multifamily buildings to spending on efficiency
programs targeted at low-income single-family buildings shall
be designed to achieve levels of savings from each building
type that are approximately proportional to the magnitude of
cost-effective lifetime savings potential in each building
type. Investment in low-income whole-building weatherization
programs shall constitute a minimum of 80% of a utility's
total budget specifically dedicated to serving low-income
customers.
The utilities shall work to bundle low-income energy
efficiency offerings with other programs that serve low-income
households to maximize the benefits going to these households.
The utilities shall market and implement low-income energy
efficiency programs in coordination with low-income assistance
programs, the Illinois Solar for All Program, and
weatherization whenever practicable. The program implementer
shall walk the customer through the enrollment process for any
programs for which the customer is eligible. The utilities
shall also pilot targeting customers with high arrearages,
high energy intensity (ratio of energy usage divided by home
or unit square footage), or energy assistance programs with
energy efficiency offerings, and then track reduction in
arrearages as a result of the targeting. This targeting and
bundling of low-income energy programs shall be offered to
both low-income single-family and multifamily customers

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(owners and residents).
The utilities shall invest in health and safety measures
appropriate and necessary for comprehensively weatherizing a
home or multifamily building, and shall implement a health and
safety fund of at least 15% of the total income-qualified
weatherization budget that shall be used for the purpose of
making grants for technical assistance, construction,
reconstruction, improvement, or repair of buildings to
facilitate their participation in the energy efficiency
programs targeted at low-income single-family and multifamily
households. These funds may also be used for the purpose of
making grants for technical assistance, construction,
reconstruction, improvement, or repair of the following
buildings to facilitate their participation in the energy
efficiency programs created by this Section: (1) buildings
that are owned or operated by registered 501(c)(3) public
charities; and (2) day care centers, day care homes, or group
day care homes, as defined under 89 Ill. Adm. Code Part 406,
407, or 408, respectively.
Each electric utility shall assess opportunities to
implement cost-effective energy efficiency measures and
programs through a public housing authority or authorities
located in its service territory. If such opportunities are
identified, the utility shall propose such measures and
programs to address the opportunities. Expenditures to address
such opportunities shall be credited toward the minimum

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procurement and expenditure requirements set forth in this
subsection (c).
Implementation of energy efficiency measures and programs
targeted at low-income households should be contracted, when
it is practicable, to independent third parties that have
demonstrated capabilities to serve such households, with a
preference for not-for-profit entities and government agencies
that have existing relationships with or experience serving
low-income communities in the State.
Each electric utility shall develop and implement
reporting procedures that address and assist in determining
the amount of energy savings that can be applied to the
low-income procurement and expenditure requirements set forth
in this subsection (c). Each electric utility shall also track
the types and quantities or volumes of insulation and air
sealing materials, and their associated energy saving
benefits, installed in energy efficiency programs targeted at
low-income single-family and multifamily households.
The electric utilities shall participate in a low-income
energy efficiency accountability committee ("the committee"),
which will directly inform the design, implementation, and
evaluation of the low-income and public-housing energy
efficiency programs. The committee shall be comprised of the
electric utilities subject to the requirements of this
Section, the gas utilities subject to the requirements of
Section 8-104 of this Act, the utilities' low-income energy

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efficiency implementation contractors, nonprofit
organizations, community action agencies, advocacy groups,
State and local governmental agencies, public-housing
organizations, and representatives of community-based
organizations, especially those living in or working with
environmental justice communities and BIPOC communities. The
committee shall be composed of 2 geographically differentiated
subcommittees: one for stakeholders in northern Illinois and
one for stakeholders in central and southern Illinois. The
subcommittees shall meet together at least twice per year.
There shall be one statewide leadership committee led by
and composed of community-based organizations that are
representative of BIPOC and environmental justice communities
and that includes equitable representation from BIPOC
communities. The leadership committee shall be composed of an
equal number of representatives from the 2 subcommittees. The
subcommittees shall address specific programs and issues, with
the leadership committee convening targeted workgroups as
needed. The leadership committee may elect to work with an
independent facilitator to solicit and organize feedback,
recommendations and meeting participation from a wide variety
of community-based stakeholders. If a facilitator is used,
they shall be fair and responsive to the needs of all
stakeholders involved in the committee.
All committee meetings must be accessible, with rotating
locations if meetings are held in-person, virtual

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participation options, and materials and agendas circulated in
advance.
There shall also be opportunities for direct input by
committee members outside of committee meetings, such as via
individual meetings, surveys, emails and calls, to ensure
robust participation by stakeholders with limited capacity and
ability to attend committee meetings. Committee meetings shall
emphasize opportunities to bundle and coordinate delivery of
low-income energy efficiency with other programs that serve
low-income communities, such as the Illinois Solar for All
Program and bill payment assistance programs. Meetings shall
include educational opportunities for stakeholders to learn
more about these additional offerings, and the committee shall
assist in figuring out the best methods for coordinated
delivery and implementation of offerings when serving
low-income communities. The committee shall directly and
equitably influence and inform utility low-income and
public-housing energy efficiency programs and priorities.
Participating utilities shall implement recommendations from
the committee whenever possible.
Participating utilities shall track and report how input
from the committee has led to new approaches and changes in
their energy efficiency portfolios. This reporting shall occur
at committee meetings and in quarterly energy efficiency
reports to the Stakeholder Advisory Group and Illinois
Commerce Commission, and other relevant reporting mechanisms.

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Participating utilities shall also report on relevant equity
data and metrics requested by the committee, such as energy
burden data, geographic, racial, and other relevant
demographic data on where programs are being delivered and
what populations programs are serving.
The Illinois Commerce Commission shall oversee and have
relevant staff participate in the committee. The committee
shall have a budget of 0.25% of each utility's entire
efficiency portfolio funding for a given year. The budget
shall be overseen by the Commission. The budget shall be used
to provide grants for community-based organizations serving on
the leadership committee, stipends for community-based
organizations participating in the committee, grants for
community-based organizations to do energy efficiency outreach
and education, and relevant meeting needs as determined by the
leadership committee. The education and outreach shall
include, but is not limited to, basic energy efficiency
education, information about low-income energy efficiency
programs, and information on the committee's purpose,
structure, and activities.
(d) Notwithstanding any other provision of law to the
contrary, a utility providing approved energy efficiency
measures and, if applicable, demand-response measures in the
State shall be permitted to recover all reasonable and
prudently incurred costs of those measures from all retail
customers, except as provided in subsection (l) of this

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Section, as follows, provided that nothing in this subsection
(d) permits the double recovery of such costs from customers:
(1) The utility may recover its costs through an
automatic adjustment clause tariff filed with and approved
by the Commission. The tariff shall be established outside
the context of a general rate case. Each year the
Commission shall initiate a review to reconcile any
amounts collected with the actual costs and to determine
the required adjustment to the annual tariff factor to
match annual expenditures. To enable the financing of the
incremental capital expenditures, including regulatory
assets, for electric utilities that serve less than
3,000,000 retail customers but more than 500,000 retail
customers in the State, the utility's actual year-end
capital structure that includes a common equity ratio,
excluding goodwill, of up to and including 50% of the
total capital structure shall be deemed reasonable and
used to set rates.
(2) A utility may recover its costs through an energy
efficiency formula rate approved by the Commission under a
filing under subsections (f) and (g) of this Section,
which shall specify the cost components that form the
basis of the rate charged to customers with sufficient
specificity to operate in a standardized manner and be
updated annually with transparent information that
reflects the utility's actual costs to be recovered during

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the applicable rate year, which is the period beginning
with the first billing day of January and extending
through the last billing day of the following December.
The energy efficiency formula rate shall be implemented
through a tariff filed with the Commission under
subsections (f) and (g) of this Section that is consistent
with the provisions of this paragraph (2) and that shall
be applicable to all delivery services customers. The
Commission shall conduct an investigation of the tariff in
a manner consistent with the provisions of this paragraph
(2), subsections (f) and (g) of this Section, and the
provisions of Article IX of this Act to the extent they do
not conflict with this paragraph (2). The energy
efficiency formula rate approved by the Commission shall
remain in effect at the discretion of the utility and
shall do the following:
(A) Provide for the recovery of the utility's
actual costs incurred under this Section that are
prudently incurred and reasonable in amount consistent
with Commission practice and law. The sole fact that a
cost differs from that incurred in a prior calendar
year or that an investment is different from that made
in a prior calendar year shall not imply the
imprudence or unreasonableness of that cost or
investment.
(B) Reflect the utility's actual year-end capital

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structure for the applicable calendar year, excluding
goodwill, subject to a determination of prudence and
reasonableness consistent with Commission practice and
law. To enable the financing of the incremental
capital expenditures, including regulatory assets, for
electric utilities that serve less than 3,000,000
retail customers but more than 500,000 retail
customers in the State, a participating electric
utility's actual year-end capital structure that
includes a common equity ratio, excluding goodwill, of
up to and including 50% of the total capital structure
shall be deemed reasonable and used to set rates.
(C) Include a cost of equity, which shall be
calculated as the sum of the following:
(i) the average for the applicable calendar
year of the monthly average yields of 30-year U.S.
Treasury bonds published by the Board of Governors
of the Federal Reserve System in its weekly H.15
Statistical Release or successor publication; and
(ii) 580 basis points.
At such time as the Board of Governors of the
Federal Reserve System ceases to include the monthly
average yields of 30-year U.S. Treasury bonds in its
weekly H.15 Statistical Release or successor
publication, the monthly average yields of the U.S.
Treasury bonds then having the longest duration

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published by the Board of Governors in its weekly H.15
Statistical Release or successor publication shall
instead be used for purposes of this paragraph (2).
(D) Permit and set forth protocols, subject to a
determination of prudence and reasonableness
consistent with Commission practice and law, for the
following:
(i) recovery of incentive compensation expense
that is based on the achievement of operational
metrics, including metrics related to budget
controls, outage duration and frequency, safety,
customer service, efficiency and productivity, and
environmental compliance; however, this protocol
shall not apply if such expense related to costs
incurred under this Section is recovered under
Article IX or Section 16-108.5 of this Act;
incentive compensation expense that is based on
net income or an affiliate's earnings per share
shall not be recoverable under the energy
efficiency formula rate;
(ii) recovery of pension and other
post-employment benefits expense, provided that
such costs are supported by an actuarial study;
however, this protocol shall not apply if such
expense related to costs incurred under this
Section is recovered under Article IX or Section

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16-108.5 of this Act;
(iii) recovery of existing regulatory assets
over the periods previously authorized by the
Commission;
(iv) as described in subsection (e),
amortization of costs incurred under this Section;
and
(v) projected, weather normalized billing
determinants for the applicable rate year.
(E) Provide for an annual reconciliation, as
described in paragraph (3) of this subsection (d),
less any deferred taxes related to the reconciliation,
with interest at an annual rate of return equal to the
utility's weighted average cost of capital, including
a revenue conversion factor calculated to recover or
refund all additional income taxes that may be payable
or receivable as a result of that return, of the energy
efficiency revenue requirement reflected in rates for
each calendar year, beginning with the calendar year
in which the utility files its energy efficiency
formula rate tariff under this paragraph (2), with
what the revenue requirement would have been had the
actual cost information for the applicable calendar
year been available at the filing date.
The utility shall file, together with its tariff, the
projected costs to be incurred by the utility during the

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rate year under the utility's multi-year plan approved
under subsections (f) and (g) of this Section, including,
but not limited to, the projected capital investment costs
and projected regulatory asset balances with
correspondingly updated depreciation and amortization
reserves and expense, that shall populate the energy
efficiency formula rate and set the initial rates under
the formula.
The Commission shall review the proposed tariff in
conjunction with its review of a proposed multi-year plan,
as specified in paragraph (5) of subsection (g) of this
Section. The review shall be based on the same evidentiary
standards, including, but not limited to, those concerning
the prudence and reasonableness of the costs incurred by
the utility, the Commission applies in a hearing to review
a filing for a general increase in rates under Article IX
of this Act. The initial rates shall take effect beginning
with the January monthly billing period following the
Commission's approval.
The tariff's rate design and cost allocation across
customer classes shall be consistent with the utility's
automatic adjustment clause tariff in effect on June 1,
2017 (the effective date of Public Act 99-906); however,
the Commission may revise the tariff's rate design and
cost allocation in subsequent proceedings under paragraph
(3) of this subsection (d).

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If the energy efficiency formula rate is terminated,
the then current rates shall remain in effect until such
time as the energy efficiency costs are incorporated into
new rates that are set under this subsection (d) or
Article IX of this Act, subject to retroactive rate
adjustment, with interest, to reconcile rates charged with
actual costs.
(3) The provisions of this paragraph (3) shall only
apply to an electric utility that has elected to file an
energy efficiency formula rate under paragraph (2) of this
subsection (d). Subsequent to the Commission's issuance of
an order approving the utility's energy efficiency formula
rate structure and protocols, and initial rates under
paragraph (2) of this subsection (d), the utility shall
file, on or before June 1 of each year, with the Chief
Clerk of the Commission its updated cost inputs to the
energy efficiency formula rate for the applicable rate
year and the corresponding new charges, as well as the
information described in paragraph (9) of subsection (g)
of this Section. Each such filing shall conform to the
following requirements and include the following
information:
(A) The inputs to the energy efficiency formula
rate for the applicable rate year shall be based on the
projected costs to be incurred by the utility during
the rate year under the utility's multi-year plan

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approved under subsections (f) and (g) of this
Section, including, but not limited to, projected
capital investment costs and projected regulatory
asset balances with correspondingly updated
depreciation and amortization reserves and expense.
The filing shall also include a reconciliation of the
energy efficiency revenue requirement that was in
effect for the prior rate year (as set by the cost
inputs for the prior rate year) with the actual
revenue requirement for the prior rate year
(determined using a year-end rate base) that uses
amounts reflected in the applicable FERC Form 1 that
reports the actual costs for the prior rate year. Any
over-collection or under-collection indicated by such
reconciliation shall be reflected as a credit against,
or recovered as an additional charge to, respectively,
with interest calculated at a rate equal to the
utility's weighted average cost of capital approved by
the Commission for the prior rate year, the charges
for the applicable rate year. Such over-collection or
under-collection shall be adjusted to remove any
deferred taxes related to the reconciliation, for
purposes of calculating interest at an annual rate of
return equal to the utility's weighted average cost of
capital approved by the Commission for the prior rate
year, including a revenue conversion factor calculated

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to recover or refund all additional income taxes that
may be payable or receivable as a result of that
return. Each reconciliation shall be certified by the
participating utility in the same manner that FERC
Form 1 is certified. The filing shall also include the
charge or credit, if any, resulting from the
calculation required by subparagraph (E) of paragraph
(2) of this subsection (d).
Notwithstanding any other provision of law to the
contrary, the intent of the reconciliation is to
ultimately reconcile both the revenue requirement
reflected in rates for each calendar year, beginning
with the calendar year in which the utility files its
energy efficiency formula rate tariff under paragraph
(2) of this subsection (d), with what the revenue
requirement determined using a year-end rate base for
the applicable calendar year would have been had the
actual cost information for the applicable calendar
year been available at the filing date.
For purposes of this Section, "FERC Form 1" means
the Annual Report of Major Electric Utilities,
Licensees and Others that electric utilities are
required to file with the Federal Energy Regulatory
Commission under the Federal Power Act, Sections 3,
4(a), 304 and 209, modified as necessary to be
consistent with 83 Ill. Adm. Code Part 415 as of May 1,

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2011. Nothing in this Section is intended to allow
costs that are not otherwise recoverable to be
recoverable by virtue of inclusion in FERC Form 1.
(B) The new charges shall take effect beginning on
the first billing day of the following January billing
period and remain in effect through the last billing
day of the next December billing period regardless of
whether the Commission enters upon a hearing under
this paragraph (3).
(C) The filing shall include relevant and
necessary data and documentation for the applicable
rate year. Normalization adjustments shall not be
required.
Within 45 days after the utility files its annual
update of cost inputs to the energy efficiency formula
rate, the Commission shall with reasonable notice,
initiate a proceeding concerning whether the projected
costs to be incurred by the utility and recovered during
the applicable rate year, and that are reflected in the
inputs to the energy efficiency formula rate, are
consistent with the utility's approved multi-year plan
under subsections (f) and (g) of this Section and whether
the costs incurred by the utility during the prior rate
year were prudent and reasonable. The Commission shall
also have the authority to investigate the information and
data described in paragraph (9) of subsection (g) of this

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Section, including the proposed adjustment to the
utility's return on equity component of its weighted
average cost of capital. During the course of the
proceeding, each objection shall be stated with
particularity and evidence provided in support thereof,
after which the utility shall have the opportunity to
rebut the evidence. Discovery shall be allowed consistent
with the Commission's Rules of Practice, which Rules of
Practice shall be enforced by the Commission or the
assigned administrative law judge. The Commission shall
apply the same evidentiary standards, including, but not
limited to, those concerning the prudence and
reasonableness of the costs incurred by the utility,
during the proceeding as it would apply in a proceeding to
review a filing for a general increase in rates under
Article IX of this Act. The Commission shall not, however,
have the authority in a proceeding under this paragraph
(3) to consider or order any changes to the structure or
protocols of the energy efficiency formula rate approved
under paragraph (2) of this subsection (d). In a
proceeding under this paragraph (3), the Commission shall
enter its order no later than the earlier of 195 days after
the utility's filing of its annual update of cost inputs
to the energy efficiency formula rate or December 15. The
utility's proposed return on equity calculation, as
described in paragraphs (7) through (9) of subsection (g)

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of this Section, shall be deemed the final, approved
calculation on December 15 of the year in which it is filed
unless the Commission enters an order on or before
December 15, after notice and hearing, that modifies such
calculation consistent with this Section. The Commission's
determinations of the prudence and reasonableness of the
costs incurred, and determination of such return on equity
calculation, for the applicable calendar year shall be
final upon entry of the Commission's order and shall not
be subject to reopening, reexamination, or collateral
attack in any other Commission proceeding, case, docket,
order, rule, or regulation; however, nothing in this
paragraph (3) shall prohibit a party from petitioning the
Commission to rehear or appeal to the courts the order
under the provisions of this Act.
(e) Beginning on June 1, 2017 (the effective date of
Public Act 99-906), a utility subject to the requirements of
this Section may elect to defer, as a regulatory asset, up to
the full amount of its expenditures incurred under this
Section for each annual period, including, but not limited to,
any expenditures incurred above the funding level set by
subsection (f) of this Section for a given year. The total
expenditures deferred as a regulatory asset in a given year
shall be amortized and recovered over a period that is equal to
the weighted average of the energy efficiency measure lives
implemented for that year that are reflected in the regulatory

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asset. The unamortized balance shall be recognized as of
December 31 for a given year. The utility shall also earn a
return on the total of the unamortized balances of all of the
energy efficiency regulatory assets, less any deferred taxes
related to those unamortized balances, at an annual rate equal
to the utility's weighted average cost of capital that
includes, based on a year-end capital structure, the utility's
actual cost of debt for the applicable calendar year and a cost
of equity, which shall be calculated as the sum of the (i) the
average for the applicable calendar year of the monthly
average yields of 30-year U.S. Treasury bonds published by the
Board of Governors of the Federal Reserve System in its weekly
H.15 Statistical Release or successor publication; and (ii)
580 basis points, including a revenue conversion factor
calculated to recover or refund all additional income taxes
that may be payable or receivable as a result of that return.
Capital investment costs shall be depreciated and recovered
over their useful lives consistent with generally accepted
accounting principles. The weighted average cost of capital
shall be applied to the capital investment cost balance, less
any accumulated depreciation and accumulated deferred income
taxes, as of December 31 for a given year.
When an electric utility creates a regulatory asset under
the provisions of this Section, the costs are recovered over a
period during which customers also receive a benefit which is
in the public interest. Accordingly, it is the intent of the

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General Assembly that an electric utility that elects to
create a regulatory asset under the provisions of this Section
shall recover all of the associated costs as set forth in this
Section. After the Commission has approved the prudence and
reasonableness of the costs that comprise the regulatory
asset, the electric utility shall be permitted to recover all
such costs, and the value and recoverability through rates of
the associated regulatory asset shall not be limited, altered,
impaired, or reduced.
(f) Beginning in 2017, each electric utility shall file an
energy efficiency plan with the Commission to meet the energy
efficiency standards for the next applicable multi-year period
beginning January 1 of the year following the filing,
according to the schedule set forth in paragraphs (1) through
(3) of this subsection (f). If a utility does not file such a
plan on or before the applicable filing deadline for the plan,
it shall face a penalty of $100,000 per day until the plan is
filed.
(1) No later than 30 days after June 1, 2017 (the
effective date of Public Act 99-906), each electric
utility shall file a 4-year energy efficiency plan
commencing on January 1, 2018 that is designed to achieve
the cumulative persisting annual savings goals specified
in paragraphs (1) through (4) of subsection (b-5) of this
Section or in paragraphs (1) through (4) of subsection
(b-15) of this Section, as applicable, through

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implementation of energy efficiency measures; however, the
goals may be reduced if the utility's expenditures are
limited pursuant to subsection (m) of this Section or, for
a utility that serves less than 3,000,000 retail
customers, if each of the following conditions are met:
(A) the plan's analysis and forecasts of the utility's
ability to acquire energy savings demonstrate that
achievement of such goals is not cost effective; and (B)
the amount of energy savings achieved by the utility as
determined by the independent evaluator for the most
recent year for which savings have been evaluated
preceding the plan filing was less than the average annual
amount of savings required to achieve the goals for the
applicable 4-year plan period. Except as provided in
subsection (m) of this Section, annual increases in
cumulative persisting annual savings goals during the
applicable 4-year plan period shall not be reduced to
amounts that are less than the maximum amount of
cumulative persisting annual savings that is forecast to
be cost-effectively achievable during the 4-year plan
period. The Commission shall review any proposed goal
reduction as part of its review and approval of the
utility's proposed plan.
(2) No later than March 1, 2021, each electric utility
shall file a 4-year energy efficiency plan commencing on
January 1, 2022 that is designed to achieve the cumulative

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persisting annual savings goals specified in paragraphs
(5) through (8) of subsection (b-5) of this Section or in
paragraphs (5) through (8) of subsection (b-15) of this
Section, as applicable, through implementation of energy
efficiency measures; however, the goals may be reduced if
either (1) clear and convincing evidence demonstrates,
through independent analysis, that the expenditure limits
in subsection (m) of this Section preclude full
achievement of the goals or (2) each of the following
conditions are met: (A) the plan's analysis and forecasts
of the utility's ability to acquire energy savings
demonstrate by clear and convincing evidence and through
independent analysis that achievement of such goals is not
cost effective; and (B) the amount of energy savings
achieved by the utility as determined by the independent
evaluator for the most recent year for which savings have
been evaluated preceding the plan filing was less than the
average annual amount of savings required to achieve the
goals for the applicable 4-year plan period. If there is
not clear and convincing evidence that achieving the
savings goals specified in paragraph (b-5) or (b-15) of
this Section is possible both cost-effectively and within
the expenditure limits in subsection (m), such savings
goals shall not be reduced. Except as provided in
subsection (m) of this Section, annual increases in
cumulative persisting annual savings goals during the

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applicable 4-year plan period shall not be reduced to
amounts that are less than the maximum amount of
cumulative persisting annual savings that is forecast to
be cost-effectively achievable during the 4-year plan
period. The Commission shall review any proposed goal
reduction as part of its review and approval of the
utility's proposed plan.
(3) No later than March 1, 2025, each electric utility
shall file a 4-year energy efficiency plan commencing on
January 1, 2026 that is designed to achieve the cumulative
persisting annual savings goals specified in paragraphs
(9) through (12) of subsection (b-5) of this Section or in
paragraphs (9) through (12) of subsection (b-15) of this
Section, as applicable, through implementation of energy
efficiency measures; however, the goals may be reduced if
either (1) clear and convincing evidence demonstrates,
through independent analysis, that the expenditure limits
in subsection (m) of this Section preclude full
achievement of the goals or (2) each of the following
conditions are met: (A) the plan's analysis and forecasts
of the utility's ability to acquire energy savings
demonstrate by clear and convincing evidence and through
independent analysis that achievement of such goals is not
cost effective; and (B) the amount of energy savings
achieved by the utility as determined by the independent
evaluator for the most recent year for which savings have

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been evaluated preceding the plan filing was less than the
average annual amount of savings required to achieve the
goals for the applicable 4-year plan period. If there is
not clear and convincing evidence that achieving the
savings goals specified in paragraphs (b-5) or (b-15) of
this Section is possible both cost-effectively and within
the expenditure limits in subsection (m), such savings
goals shall not be reduced. Except as provided in
subsection (m) of this Section, annual increases in
cumulative persisting annual savings goals during the
applicable 4-year plan period shall not be reduced to
amounts that are less than the maximum amount of
cumulative persisting annual savings that is forecast to
be cost-effectively achievable during the 4-year plan
period. The Commission shall review any proposed goal
reduction as part of its review and approval of the
utility's proposed plan.
(4) No later than March 1, 2029, and every 4 years
thereafter, each electric utility shall file a 4-year
energy efficiency plan commencing on January 1, 2030, and
every 4 years thereafter, respectively, that is designed
to achieve the cumulative persisting annual savings goals
established by the Illinois Commerce Commission pursuant
to direction of subsections (b-5) and (b-15) of this
Section, as applicable, through implementation of energy
efficiency measures; however, the goals may be reduced if

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

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reduction as part of its review and approval of the
utility's proposed plan.
Each utility's plan shall set forth the utility's
proposals to meet the energy efficiency standards identified
in subsection (b-5) or (b-15), as applicable and as such
standards may have been modified under this subsection (f),
taking into account the unique circumstances of the utility's
service territory. For those plans commencing on January 1,
2018, the Commission shall seek public comment on the
utility's plan and shall issue an order approving or
disapproving each plan no later than 105 days after June 1,
2017 (the effective date of Public Act 99-906). For those
plans commencing after December 31, 2021, the Commission shall
seek public comment on the utility's plan and shall issue an
order approving or disapproving each plan within 6 months
after its submission. If the Commission disapproves a plan,
the Commission shall, within 30 days, describe in detail the
reasons for the disapproval and describe a path by which the
utility may file a revised draft of the plan to address the
Commission's concerns satisfactorily. If the utility does not
refile with the Commission within 60 days, the utility shall
be subject to penalties at a rate of $100,000 per day until the
plan is filed. This process shall continue, and penalties
shall accrue, until the utility has successfully filed a
portfolio of energy efficiency and demand-response measures.
Penalties shall be deposited into the Energy Efficiency Trust

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Fund.
(g) In submitting proposed plans and funding levels under
subsection (f) of this Section to meet the savings goals
identified in subsection (b-5) or (b-15) of this Section, as
applicable, the utility shall:
(1) Demonstrate that its proposed energy efficiency
measures will achieve the applicable requirements that are
identified in subsection (b-5) or (b-15) of this Section,
as modified by subsection (f) of this Section.
(2) (Blank).
(2.5) Demonstrate consideration of program options for
(A) advancing new building codes, appliance standards, and
municipal regulations governing existing and new building
efficiency improvements and (B) supporting efforts to
improve compliance with new building codes, appliance
standards and municipal regulations, as potentially
cost-effective means of acquiring energy savings to count
toward savings goals.
(3) Demonstrate that its overall portfolio of
measures, not including low-income programs described in
subsection (c) of this Section, is cost-effective using
the total resource cost test or complies with paragraphs
(1) through (3) of subsection (f) of this Section and
represents a diverse cross-section of opportunities for
customers of all rate classes, other than those customers
described in subsection (l) of this Section, to

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participate in the programs. Individual measures need not
be cost effective.
(3.5) Demonstrate that the utility's plan integrates
the delivery of energy efficiency programs with natural
gas efficiency programs, programs promoting distributed
solar, programs promoting demand response and other
efforts to address bill payment issues, including, but not
limited to, LIHEAP and the Percentage of Income Payment
Plan, to the extent such integration is practical and has
the potential to enhance customer engagement, minimize
market confusion, or reduce administrative costs.
(4) Present a third-party energy efficiency
implementation program subject to the following
requirements:
(A) beginning with the year commencing January 1,
2019, electric utilities that serve more than
3,000,000 retail customers in the State shall fund
third-party energy efficiency programs in an amount
that is no less than $25,000,000 per year, and
electric utilities that serve less than 3,000,000
retail customers but more than 500,000 retail
customers in the State shall fund third-party energy
efficiency programs in an amount that is no less than
$8,350,000 per year;
(B) during 2018, the utility shall conduct a
solicitation process for purposes of requesting

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proposals from third-party vendors for those
third-party energy efficiency programs to be offered
during one or more of the years commencing January 1,
2019, January 1, 2020, and January 1, 2021; for those
multi-year plans commencing on January 1, 2022 and
January 1, 2026, the utility shall conduct a
solicitation process during 2021 and 2025,
respectively, for purposes of requesting proposals
from third-party vendors for those third-party energy
efficiency programs to be offered during one or more
years of the respective multi-year plan period; for
each solicitation process, the utility shall identify
the sector, technology, or geographical area for which
it is seeking requests for proposals; the solicitation
process must be either for programs that fill gaps in
the utility's program portfolio and for programs that
target low-income customers, business sectors,
building types, geographies, or other specific parts
of its customer base with initiatives that would be
more effective at reaching these customer segments
than the utilities' programs filed in its energy
efficiency plans;
(C) the utility shall propose the bidder
qualifications, performance measurement process, and
contract structure, which must include a performance
payment mechanism and general terms and conditions;

10400HB1700sam002 - 490 - LRB104 08228 AAS 38463 a
the proposed qualifications, process, and structure
shall be subject to Commission approval; and
(D) the utility shall retain an independent third
party to score the proposals received through the
solicitation process described in this paragraph (4),
rank them according to their cost per lifetime
kilowatt-hours saved, and assemble the portfolio of
third-party programs.
The electric utility shall recover all costs
associated with Commission-approved, third-party
administered programs regardless of the success of those
programs.
(4.5) Implement cost-effective demand-response
measures to reduce peak demand by 0.1% over the prior year
for eligible retail customers, as defined in Section
16-111.5 of this Act, and for customers that elect hourly
service from the utility pursuant to Section 16-107 of
this Act, provided those customers have not been declared
competitive. This requirement continues until December 31,
2026.
(5) Include a proposed or revised cost-recovery tariff
mechanism, as provided for under subsection (d) of this
Section, to fund the proposed energy efficiency and
demand-response measures and to ensure the recovery of the
prudently and reasonably incurred costs of
Commission-approved programs.

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(6) Provide for an annual independent evaluation of
the performance of the cost-effectiveness of the utility's
portfolio of measures, as well as a full review of the
multi-year plan results of the broader net program impacts
and, to the extent practical, for adjustment of the
measures on a going-forward basis as a result of the
evaluations. The resources dedicated to evaluation shall
not exceed 3% of portfolio resources in any given year.
(7) For electric utilities that serve more than
3,000,000 retail customers in the State:
(A) Through December 31, 2025, provide for an
adjustment to the return on equity component of the
utility's weighted average cost of capital calculated
under subsection (d) of this Section:
(i) If the independent evaluator determines
that the utility achieved a cumulative persisting
annual savings that is less than the applicable
annual incremental goal, then the return on equity
component shall be reduced by a maximum of 200
basis points in the event that the utility
achieved no more than 75% of such goal. If the
utility achieved more than 75% of the applicable
annual incremental goal but less than 100% of such
goal, then the return on equity component shall be
reduced by 8 basis points for each percent by
which the utility failed to achieve the goal.

10400HB1700sam002 - 492 - LRB104 08228 AAS 38463 a
(ii) If the independent evaluator determines
that the utility achieved a cumulative persisting
annual savings that is more than the applicable
annual incremental goal, then the return on equity
component shall be increased by a maximum of 200
basis points in the event that the utility
achieved at least 125% of such goal. If the
utility achieved more than 100% of the applicable
annual incremental goal but less than 125% of such
goal, then the return on equity component shall be
increased by 8 basis points for each percent by
which the utility achieved above the goal. If the
applicable annual incremental goal was reduced
under paragraph (1) or (2) of subsection (f) of
this Section, then the following adjustments shall
be made to the calculations described in this item
(ii):
(aa) the calculation for determining
achievement that is at least 125% of the
applicable annual incremental goal shall use
the unreduced applicable annual incremental
goal to set the value; and
(bb) the calculation for determining
achievement that is less than 125% but more
than 100% of the applicable annual incremental
goal shall use the reduced applicable annual

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incremental goal to set the value for 100%
achievement of the goal and shall use the
unreduced goal to set the value for 125%
achievement. The 8 basis point value shall
also be modified, as necessary, so that the
200 basis points are evenly apportioned among
each percentage point value between 100% and
125% achievement.
(B) For the period January 1, 2026 through
December 31, 2029 and in all subsequent 4-year
periods, provide for an adjustment to the return on
equity component of the utility's weighted average
cost of capital calculated under subsection (d) of
this Section:
(i) If the independent evaluator determines
that the utility achieved a cumulative persisting
annual savings that is less than the applicable
annual incremental goal, then the return on equity
component shall be reduced by a maximum of 200
basis points in the event that the utility
achieved no more than 66% of such goal. If the
utility achieved more than 66% of the applicable
annual incremental goal but less than 100% of such
goal, then the return on equity component shall be
reduced by 6 basis points for each percent by
which the utility failed to achieve the goal.

10400HB1700sam002 - 494 - LRB104 08228 AAS 38463 a
(ii) If the independent evaluator determines
that the utility achieved a cumulative persisting
annual savings that is more than the applicable
annual incremental goal, then the return on equity
component shall be increased by a maximum of 200
basis points in the event that the utility
achieved at least 134% of such goal. If the
utility achieved more than 100% of the applicable
annual incremental goal but less than 134% of such
goal, then the return on equity component shall be
increased by 6 basis points for each percent by
which the utility achieved above the goal. If the
applicable annual incremental goal was reduced
under paragraph (3) of subsection (f) of this
Section, then the following adjustments shall be
made to the calculations described in this item
(ii):
(aa) the calculation for determining
achievement that is at least 134% of the
applicable annual incremental goal shall use
the unreduced applicable annual incremental
goal to set the value; and
(bb) the calculation for determining
achievement that is less than 134% but more
than 100% of the applicable annual incremental
goal shall use the reduced applicable annual

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incremental goal to set the value for 100%
achievement of the goal and shall use the
unreduced goal to set the value for 134%
achievement. The 6 basis point value shall
also be modified, as necessary, so that the
200 basis points are evenly apportioned among
each percentage point value between 100% and
134% achievement.
(C) Notwithstanding the provisions of
subparagraphs (A) and (B) of this paragraph (7), if
the applicable annual incremental goal for an electric
utility is ever less than 0.6% of deemed average
weather normalized sales of electric power and energy
during calendar years 2014, 2015, and 2016, an
adjustment to the return on equity component of the
utility's weighted average cost of capital calculated
under subsection (d) of this Section shall be made as
follows:
(i) If the independent evaluator determines
that the utility achieved a cumulative persisting
annual savings that is less than would have been
achieved had the applicable annual incremental
goal been achieved, then the return on equity
component shall be reduced by a maximum of 200
basis points if the utility achieved no more than
75% of its applicable annual total savings

10400HB1700sam002 - 496 - LRB104 08228 AAS 38463 a
requirement as defined in paragraph (7.5) of this
subsection. If the utility achieved more than 75%
of the applicable annual total savings requirement
but less than 100% of such goal, then the return on
equity component shall be reduced by 8 basis
points for each percent by which the utility
failed to achieve the goal.
(ii) If the independent evaluator determines
that the utility achieved a cumulative persisting
annual savings that is more than would have been
achieved had the applicable annual incremental
goal been achieved, then the return on equity
component shall be increased by a maximum of 200
basis points if the utility achieved at least 125%
of its applicable annual total savings
requirement. If the utility achieved more than
100% of the applicable annual total savings
requirement but less than 125% of such goal, then
the return on equity component shall be increased
by 8 basis points for each percent by which the
utility achieved above the applicable annual total
savings requirement. If the applicable annual
incremental goal was reduced under paragraph (1)
or (2) of subsection (f) of this Section, then the
following adjustments shall be made to the
calculations described in this item (ii):

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(aa) the calculation for determining
achievement that is at least 125% of the
applicable annual total savings requirement
shall use the unreduced applicable annual
incremental goal to set the value; and
(bb) the calculation for determining
achievement that is less than 125% but more
than 100% of the applicable annual total
savings requirement shall use the reduced
applicable annual incremental goal to set the
value for 100% achievement of the goal and
shall use the unreduced goal to set the value
for 125% achievement. The 8 basis point value
shall also be modified, as necessary, so that
the 200 basis points are evenly apportioned
among each percentage point value between 100%
and 125% achievement.
(7.5) For purposes of this Section, the term
"applicable annual incremental goal" means the difference
between the cumulative persisting annual savings goal for
the calendar year that is the subject of the independent
evaluator's determination and the cumulative persisting
annual savings goal for the immediately preceding calendar
year, as such goals are defined in subsections (b-5) and
(b-15) of this Section and as these goals may have been
modified as provided for under subsection (b-20) and

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paragraphs (1) through (3) of subsection (f) of this
Section. Under subsections (b), (b-5), (b-10), and (b-15)
of this Section, a utility must first replace energy
savings from measures that have expired before any
progress towards achievement of its applicable annual
incremental goal may be counted. Savings may expire
because measures installed in previous years have reached
the end of their lives, because measures installed in
previous years are producing lower savings in the current
year than in the previous year, or for other reasons
identified by independent evaluators. Notwithstanding
anything else set forth in this Section, the difference
between the actual annual incremental savings achieved in
any given year, including the replacement of energy
savings that have expired, and the applicable annual
incremental goal shall not affect adjustments to the
return on equity for subsequent calendar years under this
subsection (g).
In this Section, "applicable annual total savings
requirement" means the total amount of new annual savings
that the utility must achieve in any given year to achieve
the applicable annual incremental goal. This is equal to
the applicable annual incremental goal plus the total new
annual savings that are required to replace savings that
expired in or at the end of the previous year.
(8) For electric utilities that serve less than

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3,000,000 retail customers but more than 500,000 retail
customers in the State:
(A) Through December 31, 2025, the applicable
annual incremental goal shall be compared to the
annual incremental savings as determined by the
independent evaluator.
(i) The return on equity component shall be
reduced by 8 basis points for each percent by
which the utility did not achieve 84.4% of the
applicable annual incremental goal.
(ii) The return on equity component shall be
increased by 8 basis points for each percent by
which the utility exceeded 100% of the applicable
annual incremental goal.
(iii) The return on equity component shall not
be increased or decreased if the annual
incremental savings as determined by the
independent evaluator is greater than 84.4% of the
applicable annual incremental goal and less than
100% of the applicable annual incremental goal.
(iv) The return on equity component shall not
be increased or decreased by an amount greater
than 200 basis points pursuant to this
subparagraph (A).
(B) For the period of January 1, 2026 through
December 31, 2029 and in all subsequent 4-year

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periods, the applicable annual incremental goal shall
be compared to the annual incremental savings as
determined by the independent evaluator.
(i) The return on equity component shall be
reduced by 6 basis points for each percent by
which the utility did not achieve 100% of the
applicable annual incremental goal.
(ii) The return on equity component shall be
increased by 6 basis points for each percent by
which the utility exceeded 100% of the applicable
annual incremental goal.
(iii) The return on equity component shall not
be increased or decreased by an amount greater
than 200 basis points pursuant to this
subparagraph (B).
(C) Notwithstanding provisions in subparagraphs
(A) and (B) of paragraph (7) of this subsection, if the
applicable annual incremental goal for an electric
utility is ever less than 0.6% of deemed average
weather normalized sales of electric power and energy
during calendar years 2014, 2015 and 2016, an
adjustment to the return on equity component of the
utility's weighted average cost of capital calculated
under subsection (d) of this Section shall be made as
follows:
(i) The return on equity component shall be

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

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is less than 125% but more than 100% of the
applicable annual incremental goal or the
applicable annual total savings requirement, as
applicable, shall use the reduced applicable
annual incremental goal to set the value for 100%
achievement of the goal and shall use the
unreduced goal to set the value for 125%
achievement. The 8 basis point value shall also be
modified, as necessary, so that the 200 basis
points are evenly apportioned among each
percentage point value between 100% and 125%
achievement.
(iii) For the period of January 1, 2026
through December 31, 2029 and all subsequent
4-year periods, the calculation for determining
achievement that is less than 125% or 134%, as
applicable, but more than 100% of the applicable
annual incremental goal or the applicable annual
total savings requirement, as applicable, shall
use the reduced applicable annual incremental goal
to set the value for 100% achievement of the goal
and shall use the unreduced goal to set the value
for 125% achievement. The 6 basis-point value or 8
basis-point value, as applicable, shall also be
modified, as necessary, so that the 200 basis
points are evenly apportioned among each

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percentage point value between 100% and 125% or
between 100% and 134% achievement, as applicable.
(9) The utility shall submit the energy savings data
to the independent evaluator no later than 30 days after
the close of the plan year. The independent evaluator
shall determine the cumulative persisting annual savings
for a given plan year, as well as an estimate of job
impacts and other macroeconomic impacts of the efficiency
programs for that year, no later than 120 days after the
close of the plan year. The utility shall submit an
informational filing to the Commission no later than 160
days after the close of the plan year that attaches the
independent evaluator's final report identifying the
cumulative persisting annual savings for the year and
calculates, under paragraph (7) or (8) of this subsection
(g), as applicable, any resulting change to the utility's
return on equity component of the weighted average cost of
capital applicable to the next plan year beginning with
the January monthly billing period and extending through
the December monthly billing period. However, if the
utility recovers the costs incurred under this Section
under paragraphs (2) and (3) of subsection (d) of this
Section, then the utility shall not be required to submit
such informational filing, and shall instead submit the
information that would otherwise be included in the
informational filing as part of its filing under paragraph

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(3) of such subsection (d) that is due on or before June 1
of each year.
For those utilities that must submit the informational
filing, the Commission may, on its own motion or by
petition, initiate an investigation of such filing,
provided, however, that the utility's proposed return on
equity calculation shall be deemed the final, approved
calculation on December 15 of the year in which it is filed
unless the Commission enters an order on or before
December 15, after notice and hearing, that modifies such
calculation consistent with this Section.
The adjustments to the return on equity component
described in paragraphs (7) and (8) of this subsection (g)
shall be applied as described in such paragraphs through a
separate tariff mechanism, which shall be filed by the
utility under subsections (f) and (g) of this Section.
(9.5) The utility must demonstrate how it will ensure
that program implementation contractors and energy
efficiency installation vendors will promote workforce
equity and quality jobs.
(9.6) Utilities shall collect data necessary to ensure
compliance with paragraph (9.5) no less than quarterly and
shall communicate progress toward compliance with
paragraph (9.5) to program implementation contractors and
energy efficiency installation vendors no less than
quarterly. Utilities shall work with relevant vendors,

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providing education, training, and other resources needed
to ensure compliance and, where necessary, adjusting or
terminating work with vendors that cannot assist with
compliance.
(10) Utilities required to implement efficiency
programs under subsections (b-5) and (b-10) shall report
annually to the Illinois Commerce Commission and the
General Assembly on how hiring, contracting, job training,
and other practices related to its energy efficiency
programs enhance the diversity of vendors working on such
programs. These reports must include data on vendor and
employee diversity, including data on the implementation
of paragraphs (9.5) and (9.6). If the utility is not
meeting the requirements of paragraphs (9.5) and (9.6),
the utility shall submit a plan to adjust their activities
so that they meet the requirements of paragraphs (9.5) and
(9.6) within the following year.
(h) No more than 4% of energy efficiency and
demand-response program revenue may be allocated for research,
development, or pilot deployment of new equipment or measures.
Electric utilities shall work with interested stakeholders to
formulate a plan for how these funds should be spent,
incorporate statewide approaches for these allocations, and
file a 4-year plan that demonstrates that collaboration. If a
utility files a request for modified annual energy savings
goals with the Commission, then a utility shall forgo spending

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portfolio dollars on research and development proposals.
(i) When practicable, electric utilities shall incorporate
advanced metering infrastructure data into the planning,
implementation, and evaluation of energy efficiency measures
and programs, subject to the data privacy and confidentiality
protections of applicable law.
(j) The independent evaluator shall follow the guidelines
and use the savings set forth in Commission-approved energy
efficiency policy manuals and technical reference manuals, as
each may be updated from time to time. Until such time as
measure life values for energy efficiency measures implemented
for low-income households under subsection (c) of this Section
are incorporated into such Commission-approved manuals, the
low-income measures shall have the same measure life values
that are established for same measures implemented in
households that are not low-income households.
(k) Notwithstanding any provision of law to the contrary,
an electric utility subject to the requirements of this
Section may file a tariff cancelling an automatic adjustment
clause tariff in effect under this Section or Section 8-103,
which shall take effect no later than one business day after
the date such tariff is filed. Thereafter, the utility shall
be authorized to defer and recover its expenditures incurred
under this Section through a new tariff authorized under
subsection (d) of this Section or in the utility's next rate
case under Article IX or Section 16-108.5 of this Act, with

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

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tariff, the utility shall file a reconciliation that
reconciles the moneys collected under its automatic adjustment
clause tariff with the costs incurred during the period
beginning June 1, 2016 and ending on the date that the electric
utility's automatic adjustment clause tariff was cancelled. In
the event the reconciliation reflects an under-collection, the
utility shall recover the costs as specified in this
subsection (k). If the reconciliation reflects an
over-collection, the utility shall apply the amount of such
over-collection as a one-time credit to retail customers'
bills.
(l) For the calendar years covered by a multi-year plan
commencing after December 31, 2017, subsections (a) through
(j) of this Section do not apply to eligible large private
energy customers that have chosen to opt out of multi-year
plans consistent with this subsection (1).
(1) For purposes of this subsection (l), "eligible
large private energy customer" means any retail customers,
except for federal, State, municipal, and other public
customers, of an electric utility that serves more than
3,000,000 retail customers, except for federal, State,
municipal and other public customers, in the State and
whose total highest 30 minute demand was more than 10,000
kilowatts, or any retail customers of an electric utility
that serves less than 3,000,000 retail customers but more
than 500,000 retail customers in the State and whose total

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highest 15 minute demand was more than 10,000 kilowatts.
For purposes of this subsection (l), "retail customer" has
the meaning set forth in Section 16-102 of this Act.
However, for a business entity with multiple sites located
in the State, where at least one of those sites qualifies
as an eligible large private energy customer, then any of
that business entity's sites, properly identified on a
form for notice, shall be considered eligible large
private energy customers for the purposes of this
subsection (l). A determination of whether this subsection
is applicable to a customer shall be made for each
multi-year plan beginning after December 31, 2017. The
criteria for determining whether this subsection (l) is
applicable to a retail customer shall be based on the 12
consecutive billing periods prior to the start of the
first year of each such multi-year plan.
(2) Within 45 days after September 15, 2021 (the
effective date of Public Act 102-662), the Commission
shall prescribe the form for notice required for opting
out of energy efficiency programs. The notice must be
submitted to the retail electric utility 12 months before
the next energy efficiency planning cycle. However, within
120 days after the Commission's initial issuance of the
form for notice, eligible large private energy customers
may submit a form for notice to an electric utility. The
form for notice for opting out of energy efficiency

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

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operations, the customer may provide a statement that
more efficient technology, equipment, programs, and
operations are not reasonably available as a means of
satisfying this subparagraph (E); and
(F) the effective date of the opt out, which will
be the next January 1 following notice of the opt out.
(3) Upon receipt of a properly and timely noticed
request for opt out submitted by an eligible large private
energy customer, the retail electric utility shall grant
the request, file the request with the Commission and,
beginning January 1 of the following year, the opted out
customer shall no longer be assessed the costs of the plan
and shall be prohibited from participating in that 4-year
plan cycle to give the retail utility the certainty to
design program plan proposals.
(4) Upon a customer's election to opt out under
paragraphs (1) and (2) of this subsection (l) and
commencing on the effective date of said opt out, the
account properly identified in the customer's notice under
paragraph (2) shall not be subject to any cost recovery
and shall not be eligible to participate in, or directly
benefit from, compliance with energy efficiency cumulative
persisting savings requirements under subsections (a)
through (j).
(5) A utility's cumulative persisting annual savings
targets will exclude any opted out load.

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(6) The request to opt out is only valid for the
requested plan cycle. An eligible large private energy
customer must also request to opt out for future energy
plan cycles, otherwise the customer will be included in
the future energy plan cycle.
(m) Notwithstanding the requirements of this Section, as
part of a proceeding to approve a multi-year plan under
subsections (f) and (g) of this Section if the multi-year plan
has been designed to maximize savings, but does not meet the
cost cap limitations of this Section, the Commission shall
reduce the amount of energy efficiency measures implemented
for any single year, and whose costs are recovered under
subsection (d) of this Section, by an amount necessary to
limit the estimated average net increase due to the cost of the
measures to no more than
(1) 3.5% for each of the 4 years beginning January 1,
2018,
(2) (blank),
(3) 4% for each of the 4 years beginning January 1,
2022,
(4) 4.25% for the 4 years beginning January 1, 2026,
and
(5) 4.25% plus an increase sufficient to account for
the rate of inflation between January 1, 2026 and January
1 of the first year of each subsequent 4-year plan cycle,
of the average amount paid per kilowatthour by residential

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eligible retail customers during calendar year 2015. An
electric utility may plan to spend up to 10% more in any year
during an applicable multi-year plan period to
cost-effectively achieve additional savings so long as the
average over the applicable multi-year plan period does not
exceed the percentages defined in items (1) through (5). To
determine the total amount that may be spent by an electric
utility in any single year, the applicable percentage of the
average amount paid per kilowatthour shall be multiplied by
the total amount of energy delivered by such electric utility
in the calendar year 2015, adjusted to reflect the proportion
of the utility's load attributable to customers that have
opted out of subsections (a) through (j) of this Section under
subsection (l) of this Section. For purposes of this
subsection (m), the amount paid per kilowatthour includes,
without limitation, estimated amounts paid for supply,
transmission, distribution, surcharges, and add-on taxes. For
purposes of this Section, "eligible retail customers" shall
have the meaning set forth in Section 16-111.5 of this Act.
Once the Commission has approved a plan under subsections (f)
and (g) of this Section, no subsequent rate impact
determinations shall be made.
(n) A utility shall take advantage of the efficiencies
available through existing Illinois Home Weatherization
Assistance Program infrastructure and services, such as
enrollment, marketing, quality assurance and implementation,

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which can reduce the need for similar services at a lower cost
than utility-only programs, subject to capacity constraints at
community action agencies, for both single-family and
multifamily weatherization services, to the extent Illinois
Home Weatherization Assistance Program community action
agencies provide multifamily services. A utility's plan shall
demonstrate that in formulating annual weatherization budgets,
it has sought input and coordination with community action
agencies regarding agencies' capacity to expand and maximize
Illinois Home Weatherization Assistance Program delivery using
the ratepayer dollars collected under this Section.
(Source: P.A. 102-662, eff. 9-15-21; 103-154, eff. 6-30-23;
103-613, eff. 7-1-24.)
(Text of Section after amendment by P.A. 104-458)
Sec. 8-103B. Energy efficiency and demand-response
measures.
(a) It is the policy of the State that electric utilities
are required to use cost-effective energy efficiency and
demand-response measures to reduce delivery load. Requiring
investment in cost-effective energy efficiency and
demand-response measures will reduce direct and indirect costs
to consumers by decreasing environmental impacts and by
avoiding or delaying the need for new generation,
transmission, and distribution infrastructure. It serves the
public interest to allow electric utilities to recover costs

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

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

10400HB1700sam002 - 517 - LRB104 08228 AAS 38463 a
(7) 2.8% deemed cumulative persisting annual savings
for the year ending December 31, 2024;
(8) 2.5% deemed cumulative persisting annual savings
for the year ending December 31, 2025; and
(9) 2.3% deemed cumulative persisting annual savings
for the year ending December 31, 2026.
For purposes of this Section, "cumulative persisting
annual savings" means the total electric energy savings in a
given year from measures installed in that year or in previous
years, but no earlier than January 1, 2012, that are still
operational and providing savings in that year because the
measures have not yet reached the end of their useful lives.
(b-5) Beginning in 2018 and through calendar year 2026,
electric utilities subject to this Section that serve more
than 3,000,000 retail customers in the State shall achieve the
following cumulative persisting annual savings goals, as
modified by subsection (f) of this Section and as compared to
the deemed baseline of 88,000,000 MWhs of electric power and
energy sales set forth in subsection (b), as reduced by the
number of MWhs equal to the sum of the annual consumption of
customers that have opted out of subsections (a) through (j)
of this Section under paragraph (1) of subsection (l) of this
Section as averaged across the calendar years 2014, 2015, and
2016, through the implementation of energy efficiency measures
during the applicable year and in prior years, but no earlier
than January 1, 2012:

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(1) 7.8% cumulative persisting annual savings for the
year ending December 31, 2018;
(2) 9.1% cumulative persisting annual savings for the
year ending December 31, 2019;
(3) 10.4% cumulative persisting annual savings for the
year ending December 31, 2020;
(4) 11.8% cumulative persisting annual savings for the
year ending December 31, 2021;
(5) 13.1% cumulative persisting annual savings for the
year ending December 31, 2022;
(6) 14.4% cumulative persisting annual savings for the
year ending December 31, 2023;
(7) 15.7% cumulative persisting annual savings for the
year ending December 31, 2024;
(8) 17% cumulative persisting annual savings for the
year ending December 31, 2025; and
(9) 17.9% cumulative persisting annual savings for the
year ending December 31, 2026.
(b-10) For purposes of this Section, through calendar year
2026, electric utilities subject to this Section that serve
less than 3,000,000 retail customers but more than 500,000
retail customers in the State shall be deemed to have achieved
a cumulative persisting annual savings of 6.6% from energy
efficiency measures and programs implemented during the period
beginning January 1, 2012 and ending December 31, 2017, which
is based on the deemed average weather normalized sales of

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electric power and energy during calendar years 2014, 2015,
and 2016 of 36,900,000 MWhs. For the purposes of this
subsection (b-10) and subsection (b-15), the 36,900,000 MWhs
of deemed electric power and energy sales shall be reduced by
the number of MWhs equal to the sum of the annual consumption
of customers that have opted out of subsections (a) through
(j) of this Section under paragraph (1) of subsection (l) of
this Section, as averaged across the calendar years 2014,
2015, and 2016. After 2017, the deemed value of cumulative
persisting annual savings from energy efficiency measures and
programs implemented during the period beginning January 1,
2012 and ending December 31, 2017, shall be reduced each year,
as follows, and the applicable value shall be applied to and
count toward the utility's achievement of the cumulative
persisting annual savings goals set forth in subsection
(b-15):
(1) 5.8% deemed cumulative persisting annual savings
for the year ending December 31, 2018;
(2) 5.2% deemed cumulative persisting annual savings
for the year ending December 31, 2019;
(3) 4.5% deemed cumulative persisting annual savings
for the year ending December 31, 2020;
(4) 4.0% deemed cumulative persisting annual savings
for the year ending December 31, 2021;
(5) 3.5% deemed cumulative persisting annual savings
for the year ending December 31, 2022;

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(6) 3.1% deemed cumulative persisting annual savings
for the year ending December 31, 2023;
(7) 2.8% deemed cumulative persisting annual savings
for the year ending December 31, 2024;
(8) 2.5% deemed cumulative persisting annual savings
for the year ending December 31, 2025; and
(9) 2.3% deemed cumulative persisting annual savings
for the year ending December 31, 2026.
(b-15) Beginning in 2018 and through calendar year 2026,
electric utilities subject to this Section that serve less
than 3,000,000 retail customers but more than 500,000 retail
customers in the State shall achieve the following cumulative
persisting annual savings goals, as modified by subsection
(b-20) and subsection (f) of this Section and as compared to
the deemed baseline as reduced by the number of MWhs equal to
the sum of the annual consumption of customers that have opted
out of subsections (a) through (j) of this Section under
paragraph (1) of subsection (l) of this Section as averaged
across the calendar years 2014, 2015, and 2016, through the
implementation of energy efficiency measures during the
applicable year and in prior years, but no earlier than
January 1, 2012:
(1) 7.4% cumulative persisting annual savings for the
year ending December 31, 2018;
(2) 8.2% cumulative persisting annual savings for the
year ending December 31, 2019;

10400HB1700sam002 - 521 - LRB104 08228 AAS 38463 a
(3) 9.0% cumulative persisting annual savings for the
year ending December 31, 2020;
(4) 9.8% cumulative persisting annual savings for the
year ending December 31, 2021;
(5) 10.6% cumulative persisting annual savings for the
year ending December 31, 2022;
(6) 11.4% cumulative persisting annual savings for the
year ending December 31, 2023;
(7) 12.2% cumulative persisting annual savings for the
year ending December 31, 2024;
(8) 13% cumulative persisting annual savings for the
year ending December 31, 2025; and
(9) 13.6% cumulative persisting annual savings for the
year ending December 31, 2026.
(b-16) In 2027 and each year thereafter, each electric
utility subject to this Section shall achieve the following
savings goals:
(1) A utility that serves more than 3,000,000 retail
customers in the State must achieve incremental annual
energy savings for customers in an amount that is equal to
2% of the utility's average annual electricity sales from
2021 through 2023 to customers as reduced by the number of
MWhs equal to the sum of the annual consumption of
customers that have opted out of subsections (a) through
(j) of this Section under paragraph (1) of subsection (l)
of this Section. A utility that serves less than 3,000,000

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retail customers but more than 500,000 retail customers in
the State must achieve incremental annual energy savings
for customers in an amount that is equal to 1.4% in 2027,
1.7% in 2028, and 2% in 2029 and every year thereafter of
the utility's average annual electricity sales from 2021
through 2023 to customers as reduced by the number of MWhs
equal to the sum of the annual consumption of customers
that have opted out of subsections (a) through (j) of this
Section under paragraph (1) of subsection (l) of this
Section. The incremental annual energy savings
requirements set forth in this paragraph (1) may be
reduced by 0.025 percentage points for every percentage
point increase, above the 25% minimum to be targeted at
low-income households as specified in paragraph (c) of
this Section, in the portion of total efficiency program
spending that is on low-income or moderate-income
efficiency programs. The incremental annual energy savings
requirement shall not be reduced to a level less than 0.25
percentage points less than the energy savings requirement
applicable to the calendar year, even if the sum of
low-income spending and moderate-income spending is
greater than 35% of total spending.
(2) A utility that serves less than 3,000,000 retail
customers but more than 500,000 retail customers in the
State must achieve an incremental annual coincident peak
demand savings goal from energy efficiency measures

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installed as a result of the utility's programs by
customers in an amount that is equal to the energy savings
goal from paragraph (1) of this Section divided by the
actual average ratio of kilowatt-hour savings to
coincident peak demand reduction achieved by the utility
through its energy efficiency programs in 2023. If the
season in which coincident peak demands are experienced,
the hours of the day that peak demands are experienced,
and the methods by which peak demand impacts from
efficiency measures are estimated are different in the
future than when 2023 peak demand impacts were originally
estimated, the 2023 peak demand impacts shall be
recomputed using such updated peak definitions and
estimation methods for the purpose of establishing future
coincident peak demand savings goals. To the extent that a
utility counts either improvements to the efficiency of
the use of gas and other fuels or the electrification of
gas and other fuels toward its energy savings goal, as
permitted under paragraphs (b-25) and (b-27) of this
Section, it must estimate the actual impacts on coincident
peak demand from such measures and count them, whether
positive or negative, toward its coincident peak demand
savings goal. Only coincident peak demand savings from
efficiency measures shall count toward this goal. To the
extent that some efficiency measures enable demand
response, only the peak demand savings from the energy

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efficiency upgrade shall count toward the goal. Nothing in
this Section shall limit the ability of peak demand
savings from such enabled demand-response initiatives to
count for other, non-energy efficiency performance
standard performance metrics established for the utility.
(3) Each utility's incremental annual energy savings,
and coincident peak demand savings if a utility serves
less than 3,000,000 retail customers but more than 500,000
retail customers in the State, must be achieved with an
average savings life of at least 12 years. In no event can
more than one-fifth of the incremental annual energy
savings or the coincident peak demand savings counted
toward a utility's annual savings goal in any given year
be derived from efficiency measures with average savings
lives of less than 5 years. Average savings lives may be
shorter than the average operational lives of measures
installed if the measures do not produce savings in every
year in which the measures operate or if the savings that
measures produce decline during the measures' operational
lives.
For the purposes of this Section, "incremental annual
energy savings" means the total electric energy savings
from all measures installed in a calendar year that will
be realized within 12 months of each measure's
installation; "moderate-income" means (i) for an electric
utility that serves less than 3,000,000 retail customers

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but more than 500,000 retail customers in the State,
income between 80% of area median income and 300% of the
federal poverty limit and (ii) for an electric utility
that serves more than 3,000,000 retail customers in the
State, income between 80% of area median income and 100%
of area median income; "incremental annual coincident peak
demand savings" means the total coincident peak reduction
from all energy efficiency measures installed in a
calendar year that will be realized within 12 months of
each measure's installation; "average savings life" means
the lifetime energy or coincident peak demand savings that
would be realized as a result of a utility's efficiency
programs divided by the incremental annual energy or
coincident peak demand savings such programs produce.
(b-20) Each electric utility subject to this Section may
include cost-effective voltage optimization measures in its
plans submitted under subsections (f) and (g) of this Section,
and the costs incurred by a utility to implement the measures
under a Commission-approved plan shall be recovered under the
provisions of Article IX or Section 16-108.5 of this Act. For
purposes of this Section, the measure life of voltage
optimization measures shall be 15 years. The measure life
period is independent of the depreciation rate of the voltage
optimization assets deployed. Utilities may claim savings from
voltage optimization on circuits for more than 15 years if
they can demonstrate that they have made additional

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investments necessary to enable voltage optimization savings
to continue beyond 15 years. Such demonstrations must be
subject to the review of independent evaluation.
Within 270 days after June 1, 2017 (the effective date of
Public Act 99-906), an electric utility that serves less than
3,000,000 retail customers but more than 500,000 retail
customers in the State shall file a plan with the Commission
that identifies the cost-effective voltage optimization
investment the electric utility plans to undertake through
December 31, 2024. The Commission, after notice and hearing,
shall approve or approve with modification the plan within 120
days after the plan's filing and, in the order approving or
approving with modification the plan, the Commission shall
adjust the applicable cumulative persisting annual savings
goals set forth in subsection (b-15) to reflect any amount of
cost-effective energy savings approved by the Commission that
is greater than or less than the following cumulative
persisting annual savings values attributable to voltage
optimization for the applicable year:
(1) 0.0% of cumulative persisting annual savings for
the year ending December 31, 2018;
(2) 0.17% of cumulative persisting annual savings for
the year ending December 31, 2019;
(3) 0.17% of cumulative persisting annual savings for
the year ending December 31, 2020;
(4) 0.33% of cumulative persisting annual savings for

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the year ending December 31, 2021;
(5) 0.5% of cumulative persisting annual savings for
the year ending December 31, 2022;
(6) 0.67% of cumulative persisting annual savings for
the year ending December 31, 2023;
(7) 0.83% of cumulative persisting annual savings for
the year ending December 31, 2024; and
(8) 1.0% of cumulative persisting annual savings for
the year ending December 31, 2025 and all subsequent
years.
(b-25) In the event an electric utility jointly offers an
energy efficiency measure or program with a gas utility under
plans approved under this Section and Section 8-104 of this
Act, the electric utility may continue offering the program,
including the gas energy efficiency measures, in the event the
gas utility discontinues funding the program. In that event,
the energy savings value associated with such other fuels
shall be converted to electric energy savings on an equivalent
Btu basis for the premises. However, the electric utility
shall prioritize programs for low-income residential customers
to the extent practicable. An electric utility may recover the
costs of offering the gas energy efficiency measures under
this subsection (b-25).
For those energy efficiency measures or programs that save
both electricity and other fuels but are not jointly offered
with a gas utility under plans approved under this Section and

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Section 8-104 or not offered with an affiliated gas utility
under paragraph (6) of subsection (f) of Section 8-104 of this
Act, the electric utility may count savings of fuels other
than electricity toward the achievement of its annual savings
goal, and the energy savings value associated with such other
fuels shall be converted to electric energy savings on an
equivalent Btu basis at the premises.
For an electric utility that serves more than 3,000,000
retail customers in the State, on and after January 1, 2027,
the electric utility may only count savings of other fuels
under this subsection (b-25) toward the achievement of its
annual electric energy savings goal when such other fuel
savings are from weatherization measures that reduce heat loss
through the building envelope, insulating mechanical systems,
or the heating distribution system, including, but not limited
to, air sealing and building shell measures. This limitation
on counting other fuel savings from efficiency measures toward
a utility's energy savings goal shall not affect the utility's
ability to claim savings from electrification measures
installed pursuant to the requirements in subsection (b-27).
In no event shall more than 10% of each year's applicable
annual total savings requirement, as defined in paragraph
(7.5) of subsection (g) of this Section be met through savings
of fuels other than electricity. For an electric utility that
serves more than 3,000,000 retail customers in the State, in
no event shall more than 30% of each year's incremental annual

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energy savings requirement, as defined in subsection (b-16) of
this Section, be met through savings of fuels other than
electricity. For an electric utility that serves less than
3,000,000 retail customers but more than 500,000 retail
customers in the State, in no event shall more than 20% of each
year's incremental annual energy savings requirement, as
defined in subsection (b-16) of this Section, be met through
savings of fuels other than electricity.
(b-27) Beginning in 2022, an electric utility may offer
and promote measures that electrify space heating, water
heating, cooling, drying, cooking, industrial processes, and
other building and industrial end uses that would otherwise be
served by combustion of fossil fuel at the premises, provided
that the electrification measures reduce total energy
consumption at the premises. The electric utility may count
the reduction in energy consumption at the premises toward
achievement of its annual savings goals. The reduction in
energy consumption at the premises shall be calculated as the
difference between: (A) the reduction in Btu consumption of
fossil fuels as a result of electrification, converted to
kilowatt-hour equivalents by dividing by 3,412 Btus per
kilowatt hour; and (B) the increase in kilowatt hours of
electricity consumption resulting from the displacement of
fossil fuel consumption as a result of electrification. An
electric utility may recover the costs of offering and
promoting electrification measures under this subsection

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(b-27).
At least 33% of all costs of offering and promoting
electrification measures under this subsection (b-27) must be
for supporting installation of electrification measures
through programs exclusively targeted to low-income
households. The percentage requirement may be reduced if the
utility can demonstrate that it is not possible to achieve the
level of low-income electrification spending, while supporting
programs for non-low-income residential and business
electrification, because of limitations regarding the number
of low-income households in its service territory that would
be able to meet program eligibility requirements set forth in
the multi-year energy efficiency plan. If the 33% low-income
electrification spending requirement is reduced, the utility
must prioritize support of low-income electrification in
housing that meets program eligibility requirements over
electrification spending on non-low-income residential or
business customers.
The ratio of spending on electrification measures targeted
to low-income, multifamily buildings to spending on
electrification measures targeted to low-income, single-family
buildings shall be designed to achieve levels of
electrification savings from each building type that are
approximately proportional to the magnitude of cost-effective
electrification savings potential in each building type.
In no event shall electrification savings counted toward

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each year's applicable annual total savings requirement, as
defined in paragraph (7.5) of subsection (g) of this Section,
or counted toward each year's incremental annual energy
savings, as defined in paragraph (b-16) of this Section, be
greater than:
(1) 5% per year for each year from 2022 through 2025;
(2) 20% per year for 2026 and all subsequent years;
and
(3) (blank).
The limitations on electrification savings that may be counted
toward a utility's annual savings goals are separate from and
in addition to the subsection (b-25) limitations governing the
counting of the other fuel savings resulting from efficiency
measures and programs.
As part of the annual informational filing to the
Commission that is required under paragraph (9) of subsection
(g) of this Section, each utility shall identify the specific
electrification measures offered under this subsection (b-27);
the quantity of each electrification measure that was
installed by its customers; the average total cost, average
utility cost, average reduction in fossil fuel consumption,
and average increase in electricity consumption associated
with each electrification measure; the portion of
installations of each electrification measure that were in
low-income single-family housing, low-income multifamily
housing, non-low-income single-family housing, non-low-income

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

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equal to public housing's share of public building energy
consumption.
The utilities shall also implement energy efficiency
measures targeted at low-income households, which, for
purposes of this Section, shall be defined as households at or
below 80% of area median income, and expenditures to implement
the measures shall be no less than 25% of total energy
efficiency program spending approved by the Commission
pursuant to review of plans filed under subsection (f) of this
Section The ratio of spending on efficiency programs targeted
at low-income multifamily buildings to spending on efficiency
programs targeted at low-income single-family buildings shall
be designed to achieve levels of savings from each building
type that are approximately proportional to the magnitude of
cost-effective lifetime savings potential in each building
type. Investment in low-income whole-building weatherization
programs shall constitute a minimum of 80% of a utility's
total budget specifically dedicated to serving low-income
customers.
The utilities shall work to bundle low-income energy
efficiency offerings with other programs that serve low-income
households to maximize the benefits going to these households.
The utilities shall market and implement low-income energy
efficiency programs in coordination with low-income assistance
programs, the Illinois Solar for All Program, and
weatherization whenever practicable. The program implementer

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shall walk the customer through the enrollment process for any
programs for which the customer is eligible. The utilities
shall also pilot targeting customers with high arrearages,
high energy intensity (ratio of energy usage divided by home
or unit square footage), or energy assistance programs with
energy efficiency offerings, and then track reduction in
arrearages as a result of the targeting. This targeting and
bundling of low-income energy programs shall be offered to
both low-income single-family and multifamily customers
(owners and residents).
The utilities shall invest in health and safety measures
appropriate and necessary for comprehensively weatherizing a
home or multifamily building, and shall implement a health and
safety fund of at least 15% of the total income-qualified
weatherization budget that shall be used for the purpose of
making grants for technical assistance, construction,
reconstruction, improvement, or repair of buildings to
facilitate their participation in the energy efficiency
programs targeted at low-income single-family and multifamily
households. These funds may also be used for the purpose of
making grants for technical assistance, construction,
reconstruction, improvement, or repair of the following
buildings to facilitate their participation in the energy
efficiency programs created by this Section: (1) buildings
that are owned or operated by registered 501(c)(3) public
charities; and (2) day care centers, day care homes, or group

10400HB1700sam002 - 535 - LRB104 08228 AAS 38463 a
day care homes, as defined under 89 Ill. Adm. Code Part 406,
407, or 408, respectively.
Each electric utility shall assess opportunities to
implement cost-effective energy efficiency measures and
programs through a public housing authority or authorities
located in its service territory. If such opportunities are
identified, the utility shall propose such measures and
programs to address the opportunities. Expenditures to address
such opportunities shall be credited toward the minimum
procurement and expenditure requirements set forth in this
subsection (c).
Implementation of energy efficiency measures and programs
targeted at low-income households should be contracted, when
it is practicable, to independent third parties that have
demonstrated capabilities to serve such households, with a
preference for not-for-profit entities and government agencies
that have existing relationships with or experience serving
low-income communities in the State.
Each electric utility shall develop and implement
reporting procedures that address and assist in determining
the amount of energy savings that can be applied to the
low-income procurement and expenditure requirements set forth
in this subsection (c). Each electric utility shall also track
the types and quantities or volumes of insulation and air
sealing materials, and their associated energy saving
benefits, installed in energy efficiency programs targeted at

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

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the leadership committee convening targeted workgroups as
needed. The leadership committee may elect to work with an
independent facilitator to solicit and organize feedback,
recommendations and meeting participation from a wide variety
of community-based stakeholders. If a facilitator is used,
they shall be fair and responsive to the needs of all
stakeholders involved in the committee. For a utility that
serves more than 3,000,000 retail customers in the State, if a
facilitator is used, they shall be retained by Commission
staff.
All committee meetings must be accessible, with rotating
locations if meetings are held in-person, virtual
participation options, and materials and agendas circulated in
advance.
There shall also be opportunities for direct input by
committee members outside of committee meetings, such as via
individual meetings, surveys, emails and calls, to ensure
robust participation by stakeholders with limited capacity and
ability to attend committee meetings. Committee meetings shall
emphasize opportunities to bundle and coordinate delivery of
low-income energy efficiency with other programs that serve
low-income communities, such as the Illinois Solar for All
Program and bill payment assistance programs. Meetings shall
include educational opportunities for stakeholders to learn
more about these additional offerings, and the committee shall
assist in figuring out the best methods for coordinated

10400HB1700sam002 - 538 - LRB104 08228 AAS 38463 a
delivery and implementation of offerings when serving
low-income communities. The committee shall directly and
equitably influence and inform utility low-income and
public-housing energy efficiency programs and priorities.
Participating utilities shall implement recommendations from
the committee whenever possible.
Participating utilities shall track and report how input
from the committee has led to new approaches and changes in
their energy efficiency portfolios. This reporting shall occur
at committee meetings and in quarterly energy efficiency
reports to the Stakeholder Advisory Group and Illinois
Commerce Commission, and other relevant reporting mechanisms.
Participating utilities shall also report on relevant equity
data and metrics requested by the committee, such as energy
burden data, geographic, racial, and other relevant
demographic data on where programs are being delivered and
what populations programs are serving.
The Illinois Commerce Commission shall oversee and have
relevant staff participate in the committee. The committee
shall have a budget of 0.25% of each utility's entire
efficiency portfolio funding for a given year. The budget
shall be overseen by the Commission. The budget shall be used
to provide grants for community-based organizations serving on
the leadership committee, stipends for community-based
organizations participating in the committee, grants for
community-based organizations to do energy efficiency outreach

10400HB1700sam002 - 539 - LRB104 08228 AAS 38463 a
and education, and relevant meeting needs as determined by the
leadership committee. The education and outreach shall
include, but is not limited to, basic energy efficiency
education, information about low-income energy efficiency
programs, and information on the committee's purpose,
structure, and activities.
(d) Notwithstanding any other provision of law to the
contrary, a utility providing approved energy efficiency
measures and, if applicable, demand-response measures in the
State shall be permitted to recover all reasonable and
prudently incurred costs of those measures from all retail
customers, except as provided in subsection (l) of this
Section, as follows, provided that nothing in this subsection
(d) permits the double recovery of such costs from customers:
(1) The utility may recover its costs through an
automatic adjustment clause tariff filed with and approved
by the Commission. The tariff shall be established outside
the context of a general rate case. Each year the
Commission shall initiate a review to reconcile any
amounts collected with the actual costs and to determine
the required adjustment to the annual tariff factor to
match annual expenditures. To enable the financing of the
incremental capital expenditures, including regulatory
assets, for electric utilities that serve less than
3,000,000 retail customers but more than 500,000 retail
customers in the State, the utility's actual year-end

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capital structure that includes a common equity ratio,
excluding goodwill, of up to and including 50% of the
total capital structure shall be deemed reasonable and
used to set rates.
(2) A utility may recover its costs through an energy
efficiency formula rate approved by the Commission under a
filing under subsections (f) and (g) of this Section,
which shall specify the cost components that form the
basis of the rate charged to customers with sufficient
specificity to operate in a standardized manner and be
updated annually with transparent information that
reflects the utility's actual costs to be recovered during
the applicable rate year, which is the period beginning
with the first billing day of January and extending
through the last billing day of the following December.
The energy efficiency formula rate shall be implemented
through a tariff filed with the Commission under
subsections (f) and (g) of this Section that is consistent
with the provisions of this paragraph (2) and that shall
be applicable to all delivery services customers. The
Commission shall conduct an investigation of the tariff in
a manner consistent with the provisions of this paragraph
(2), subsections (f) and (g) of this Section, and the
provisions of Article IX of this Act to the extent they do
not conflict with this paragraph (2). The energy
efficiency formula rate approved by the Commission shall

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remain in effect at the discretion of the utility and
shall do the following:
(A) Provide for the recovery of the utility's
actual costs incurred under this Section that are
prudently incurred and reasonable in amount consistent
with Commission practice and law. The sole fact that a
cost differs from that incurred in a prior calendar
year or that an investment is different from that made
in a prior calendar year shall not imply the
imprudence or unreasonableness of that cost or
investment.
(B) Reflect the utility's actual year-end capital
structure for the applicable calendar year, excluding
goodwill, subject to a determination of prudence and
reasonableness consistent with Commission practice and
law. To enable the financing of the incremental
capital expenditures, including regulatory assets, for
electric utilities that serve less than 3,000,000
retail customers but more than 500,000 retail
customers in the State, a participating electric
utility's actual year-end capital structure that
includes a common equity ratio, excluding goodwill, of
up to and including 50% of the total capital structure
shall be deemed reasonable and used to set rates.
(C) Include a cost of equity that shall be equal to
the baseline cost of equity approved by the Commission

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for the utility's electric distribution rates
effective during the applicable year, whether those
rates are set pursuant to Section 9-201, subparagraph
(B) of paragraph (3) of subsection (d) of Section
16-108.18, or any successor electric distribution
ratemaking paradigm.
(D) Permit and set forth protocols, subject to a
determination of prudence and reasonableness
consistent with Commission practice and law, for the
following:
(i) recovery of incentive compensation expense
that is based on the achievement of operational
metrics, including metrics related to budget
controls, outage duration and frequency, safety,
customer service, efficiency and productivity, and
environmental compliance; however, this protocol
shall not apply if such expense related to costs
incurred under this Section is recovered under
Article IX or Section 16-108.5 of this Act;
incentive compensation expense that is based on
net income or an affiliate's earnings per share
shall not be recoverable under the energy
efficiency formula rate;
(ii) recovery of pension and other
post-employment benefits expense, provided that
such costs are supported by an actuarial study;

10400HB1700sam002 - 543 - LRB104 08228 AAS 38463 a
however, this protocol shall not apply if such
expense related to costs incurred under this
Section is recovered under Article IX or Section
16-108.5 of this Act;
(iii) recovery of existing regulatory assets
over the periods previously authorized by the
Commission;
(iv) as described in subsection (e),
amortization of costs incurred under this Section;
and
(v) projected, weather normalized billing
determinants for the applicable rate year.
(E) Provide for an annual reconciliation, as
described in paragraph (3) of this subsection (d),
less any deferred taxes related to the reconciliation,
with interest at an annual rate of return equal to the
utility's weighted average cost of capital, including
a revenue conversion factor calculated to recover or
refund all additional income taxes that may be payable
or receivable as a result of that return, of the energy
efficiency revenue requirement reflected in rates for
each calendar year, beginning with the calendar year
in which the utility files its energy efficiency
formula rate tariff under this paragraph (2), with
what the revenue requirement would have been had the
actual cost information for the applicable calendar

10400HB1700sam002 - 544 - LRB104 08228 AAS 38463 a
year been available at the filing date.
The utility shall file, together with its tariff, the
projected costs to be incurred by the utility during the
rate year under the utility's multi-year plan approved
under subsections (f) and (g) of this Section, including,
but not limited to, the projected capital investment costs
and projected regulatory asset balances with
correspondingly updated depreciation and amortization
reserves and expense, that shall populate the energy
efficiency formula rate and set the initial rates under
the formula.
The Commission shall review the proposed tariff in
conjunction with its review of a proposed multi-year plan,
as specified in paragraph (5) of subsection (g) of this
Section. The review shall be based on the same evidentiary
standards, including, but not limited to, those concerning
the prudence and reasonableness of the costs incurred by
the utility, the Commission applies in a hearing to review
a filing for a general increase in rates under Article IX
of this Act. The initial rates shall take effect beginning
with the January monthly billing period following the
Commission's approval.
The tariff's rate design and cost allocation across
customer classes shall be consistent with the utility's
automatic adjustment clause tariff in effect on June 1,
2017 (the effective date of Public Act 99-906); however,

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the Commission may revise the tariff's rate design and
cost allocation in subsequent proceedings under paragraph
(3) of this subsection (d).
If the energy efficiency formula rate is terminated,
the then current rates shall remain in effect until such
time as the energy efficiency costs are incorporated into
new rates that are set under this subsection (d) or
Article IX of this Act, subject to retroactive rate
adjustment, with interest, to reconcile rates charged with
actual costs.
(3) The provisions of this paragraph (3) shall only
apply to an electric utility that has elected to file an
energy efficiency formula rate under paragraph (2) of this
subsection (d). Subsequent to the Commission's issuance of
an order approving the utility's energy efficiency formula
rate structure and protocols, and initial rates under
paragraph (2) of this subsection (d), the utility shall
file, on or before June 1 of each year, with the Chief
Clerk of the Commission its updated cost inputs to the
energy efficiency formula rate for the applicable rate
year and the corresponding new charges, as well as the
information described in paragraph (9) of subsection (g)
of this Section. Each such filing shall conform to the
following requirements and include the following
information:
(A) The inputs to the energy efficiency formula

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rate for the applicable rate year shall be based on the
projected costs to be incurred by the utility during
the rate year under the utility's multi-year plan
approved under subsections (f) and (g) of this
Section, including, but not limited to, projected
capital investment costs and projected regulatory
asset balances with correspondingly updated
depreciation and amortization reserves and expense.
The filing shall also include a reconciliation of the
energy efficiency revenue requirement that was in
effect for the prior rate year (as set by the cost
inputs for the prior rate year) with the actual
revenue requirement for the prior rate year
(determined using a year-end rate base) that uses
amounts reflected in the applicable FERC Form 1 that
reports the actual costs for the prior rate year. Any
over-collection or under-collection indicated by such
reconciliation shall be reflected as a credit against,
or recovered as an additional charge to, respectively,
with interest calculated at a rate equal to the
utility's weighted average cost of capital approved by
the Commission for the prior rate year, the charges
for the applicable rate year. Such over-collection or
under-collection shall be adjusted to remove any
deferred taxes related to the reconciliation, for
purposes of calculating interest at an annual rate of

10400HB1700sam002 - 547 - LRB104 08228 AAS 38463 a
return equal to the utility's weighted average cost of
capital approved by the Commission for the prior rate
year, including a revenue conversion factor calculated
to recover or refund all additional income taxes that
may be payable or receivable as a result of that
return. Each reconciliation shall be certified by the
participating utility in the same manner that FERC
Form 1 is certified. The filing shall also include the
charge or credit, if any, resulting from the
calculation required by subparagraph (E) of paragraph
(2) of this subsection (d).
Notwithstanding any other provision of law to the
contrary, the intent of the reconciliation is to
ultimately reconcile both the revenue requirement
reflected in rates for each calendar year, beginning
with the calendar year in which the utility files its
energy efficiency formula rate tariff under paragraph
(2) of this subsection (d), with what the revenue
requirement determined using a year-end rate base for
the applicable calendar year would have been had the
actual cost information for the applicable calendar
year been available at the filing date.
For purposes of this Section, "FERC Form 1" means
the Annual Report of Major Electric Utilities,
Licensees and Others that electric utilities are
required to file with the Federal Energy Regulatory

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Commission under the Federal Power Act, Sections 3,
4(a), 304 and 209, modified as necessary to be
consistent with 83 Ill. Adm. Code Part 415 as of May 1,
2011. Nothing in this Section is intended to allow
costs that are not otherwise recoverable to be
recoverable by virtue of inclusion in FERC Form 1.
(B) The new charges shall take effect beginning on
the first billing day of the following January billing
period and remain in effect through the last billing
day of the next December billing period regardless of
whether the Commission enters upon a hearing under
this paragraph (3).
(C) The filing shall include relevant and
necessary data and documentation for the applicable
rate year. Normalization adjustments shall not be
required.
Within 45 days after the utility files its annual
update of cost inputs to the energy efficiency formula
rate, the Commission shall with reasonable notice,
initiate a proceeding concerning whether the projected
costs to be incurred by the utility and recovered during
the applicable rate year, and that are reflected in the
inputs to the energy efficiency formula rate, are
consistent with the utility's approved multi-year plan
under subsections (f) and (g) of this Section and whether
the costs incurred by the utility during the prior rate

10400HB1700sam002 - 549 - LRB104 08228 AAS 38463 a
year were prudent and reasonable. The Commission shall
also have the authority to investigate the information and
data described in paragraph (9) of subsection (g) of this
Section, including the proposed adjustment to the
utility's return on equity component of its weighted
average cost of capital. During the course of the
proceeding, each objection shall be stated with
particularity and evidence provided in support thereof,
after which the utility shall have the opportunity to
rebut the evidence. Discovery shall be allowed consistent
with the Commission's Rules of Practice, which Rules of
Practice shall be enforced by the Commission or the
assigned administrative law judge. The Commission shall
apply the same evidentiary standards, including, but not
limited to, those concerning the prudence and
reasonableness of the costs incurred by the utility,
during the proceeding as it would apply in a proceeding to
review a filing for a general increase in rates under
Article IX of this Act. The Commission shall not, however,
have the authority in a proceeding under this paragraph
(3) to consider or order any changes to the structure or
protocols of the energy efficiency formula rate approved
under paragraph (2) of this subsection (d). In a
proceeding under this paragraph (3), the Commission shall
enter its order no later than the earlier of 195 days after
the utility's filing of its annual update of cost inputs

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to the energy efficiency formula rate or December 15. The
utility's proposed return on equity calculation, as
described in paragraphs (7) through (9) of subsection (g)
of this Section, shall be deemed the final, approved
calculation on December 15 of the year in which it is filed
unless the Commission enters an order on or before
December 15, after notice and hearing, that modifies such
calculation consistent with this Section. The Commission's
determinations of the prudence and reasonableness of the
costs incurred, and determination of such return on equity
calculation, for the applicable calendar year shall be
final upon entry of the Commission's order and shall not
be subject to reopening, reexamination, or collateral
attack in any other Commission proceeding, case, docket,
order, rule, or regulation; however, nothing in this
paragraph (3) shall prohibit a party from petitioning the
Commission to rehear or appeal to the courts the order
under the provisions of this Act.
(e) Beginning on June 1, 2017 (the effective date of
Public Act 99-906), a utility subject to the requirements of
this Section may elect to defer, as a regulatory asset, up to
the full amount of its expenditures incurred under this
Section for each annual period, including, but not limited to,
any expenditures incurred above the funding level set by
subsection (f) of this Section for a given year. The total
expenditures deferred as a regulatory asset in a given year

10400HB1700sam002 - 551 - LRB104 08228 AAS 38463 a
shall be amortized and recovered over a period that is equal to
the weighted average of the energy efficiency measure lives
implemented for that year that are reflected in the regulatory
asset. The unamortized balance shall be recognized as of
December 31 for a given year. The utility shall also earn a
return on the total of the unamortized balances of all of the
energy efficiency regulatory assets, less any deferred taxes
related to those unamortized balances, at an annual rate equal
to the utility's weighted average cost of capital that
includes, based on a year-end capital structure, the utility's
actual cost of debt for the applicable calendar year and a cost
of equity, which shall be determined as set forth in
subparagraph (C) of paragraph (2) of subsection of this
Section, including a revenue conversion factor calculated to
recover or refund all additional income taxes that may be
payable or receivable as a result of that return. Capital
investment costs shall be depreciated and recovered over their
useful lives consistent with generally accepted accounting
principles. The weighted average cost of capital shall be
applied to the capital investment cost balance, less any
accumulated depreciation and accumulated deferred income
taxes, as of December 31 for a given year.
When an electric utility creates a regulatory asset under
the provisions of this Section, the costs are recovered over a
period during which customers also receive a benefit which is
in the public interest. Accordingly, it is the intent of the

10400HB1700sam002 - 552 - LRB104 08228 AAS 38463 a
General Assembly that an electric utility that elects to
create a regulatory asset under the provisions of this Section
shall recover all of the associated costs as set forth in this
Section. After the Commission has approved the prudence and
reasonableness of the costs that comprise the regulatory
asset, the electric utility shall be permitted to recover all
such costs, and the value and recoverability through rates of
the associated regulatory asset shall not be limited, altered,
impaired, or reduced.
(f) Beginning in 2017, each electric utility shall file an
energy efficiency plan with the Commission to meet the energy
efficiency standards for the next applicable multi-year period
beginning January 1 of the year following the filing,
according to the schedule set forth in paragraphs (1) through
(3) of this subsection (f). If a utility does not file such a
plan on or before the applicable filing deadline for the plan,
it shall face a penalty of $100,000 per day until the plan is
filed.
(1) No later than 30 days after June 1, 2017 (the
effective date of Public Act 99-906), each electric
utility shall file a 4-year energy efficiency plan
commencing on January 1, 2018 that is designed to achieve
the cumulative persisting annual savings goals specified
in paragraphs (1) through (4) of subsection (b-5) of this
Section or in paragraphs (1) through (4) of subsection
(b-15) of this Section, as applicable, through

10400HB1700sam002 - 553 - LRB104 08228 AAS 38463 a
implementation of energy efficiency measures; however, the
goals may be reduced if the utility's expenditures are
limited pursuant to subsection (m) of this Section or, for
a utility that serves less than 3,000,000 retail
customers, if each of the following conditions are met:
(A) the plan's analysis and forecasts of the utility's
ability to acquire energy savings demonstrate that
achievement of such goals is not cost effective; and (B)
the amount of energy savings achieved by the utility as
determined by the independent evaluator for the most
recent year for which savings have been evaluated
preceding the plan filing was less than the average annual
amount of savings required to achieve the goals for the
applicable 4-year plan period. Except as provided in
subsection (m) of this Section, annual increases in
cumulative persisting annual savings goals during the
applicable 4-year plan period shall not be reduced to
amounts that are less than the maximum amount of
cumulative persisting annual savings that is forecast to
be cost-effectively achievable during the 4-year plan
period. The Commission shall review any proposed goal
reduction as part of its review and approval of the
utility's proposed plan.
(2) No later than March 1, 2021, each electric utility
shall file a 4-year energy efficiency plan commencing on
January 1, 2022 that is designed to achieve the cumulative

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persisting annual savings goals specified in paragraphs
(5) through (8) of subsection (b-5) of this Section or in
paragraphs (5) through (8) of subsection (b-15) of this
Section, as applicable, through implementation of energy
efficiency measures; however, the goals may be reduced if
either (1) clear and convincing evidence demonstrates,
through independent analysis, that the expenditure limits
in subsection (m) of this Section preclude full
achievement of the goals or (2) each of the following
conditions are met: (A) the plan's analysis and forecasts
of the utility's ability to acquire energy savings
demonstrate by clear and convincing evidence and through
independent analysis that achievement of such goals is not
cost effective; and (B) the amount of energy savings
achieved by the utility as determined by the independent
evaluator for the most recent year for which savings have
been evaluated preceding the plan filing was less than the
average annual amount of savings required to achieve the
goals for the applicable 4-year plan period. If there is
not clear and convincing evidence that achieving the
savings goals specified in paragraph (b-5) or (b-15) of
this Section is possible both cost-effectively and within
the expenditure limits in subsection (m), such savings
goals shall not be reduced. Except as provided in
subsection (m) of this Section, annual increases in
cumulative persisting annual savings goals during the

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applicable 4-year plan period shall not be reduced to
amounts that are less than the maximum amount of
cumulative persisting annual savings that is forecast to
be cost-effectively achievable during the 4-year plan
period. The Commission shall review any proposed goal
reduction as part of its review and approval of the
utility's proposed plan.
(2.5) Provisions of the multi-year plans for calendar
years 2026 through 2029 that relate to calendar year 2026
and that were filed by the electric utilities on February
28, 2025 shall remain in effect through calendar year
2026. Provisions of the plans for calendar years 2027
through 2029 shall be modified and resubmitted to the
Commission by the electric utilities pursuant to paragraph
(3) of this subsection (f).
(3) No later than the effective date of this
amendatory Act of the 104th General Assembly, each
electric utility shall file a 3-year energy efficiency
plan commencing on January 1, 2027 that is designed to
achieve, through implementation of energy efficiency
measures, lifetime energy savings equal to the product of
the incremental annual energy savings goals defined by
paragraph (1) of subsection (b-16) and the minimum average
savings life defined by paragraph (3) of subsection
(b-16). The 3-year energy efficiency plan of a utility
that serves less than 3,000,000 retail customers but more

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than 500,000 retail customers in the State must also be
designed to achieve lifetime peak demand savings equal to
the product of the incremental annual peak demand savings
goals defined by paragraph (2) of subsection (b-16) and
the minimum average savings life defined by paragraph (3)
of subsection (b-16) through implementation of energy
efficiency measures. The savings goals may be reduced if:
(i) clear and convincing evidence and independent analysis
demonstrates that the expenditure limits in subsection (m)
of this Section preclude full achievement of the goals,
(ii) each of the following conditions are met: (A) the
plan's analysis and forecasts of the utility's ability to
acquire energy savings demonstrate by clear and convincing
evidence and through independent analysis that achievement
of such goals is not cost-effective; and (B) the amount of
energy savings achieved by the utility, as determined by
the independent evaluator, for the most recent year for
which savings have been evaluated preceding the plan
filing was less than the average annual amount of savings
required to achieve the goals for the applicable
multi-year plan period, or (iii) changes in federal law,
programs, or tariffs have a significant and demonstrable
impact on the cost of delivering measures and programs. If
there is not clear and convincing evidence that achieving
the savings goals specified in subsection (b-16) is not
possible both cost-effectively and within the expenditure

10400HB1700sam002 - 557 - LRB104 08228 AAS 38463 a
limits in subsection (m), such savings goals shall not be
reduced. Except as provided in subsection (m), annual
savings goals during the applicable multi-year plan period
shall not be reduced to amounts that are less than the
maximum amount of annual savings that is forecasted to be
cost-effectively achievable during the applicable
multi-year plan period. The Commission shall review any
proposed goal reduction as part of its review and approval
of the utility's proposed plan.
(4) No later than March 1, 2029, and every 4 years
thereafter, each electric utility shall file a 4-year
energy efficiency plan commencing on January 1, 2030, and
every 4 years thereafter, respectively, that is designed
to achieve, through implementation of energy efficiency
measures, lifetime energy savings equal to the product of
the incremental annual energy savings goals defined by
paragraph (1) of subsection (b-16) and the minimum average
savings life described in paragraph (3) (C) of subsection
(b-16) of this Section. The multi-year energy efficiency
plan of a utility that serves less than 3,000,000 retail
customers but more than 500,000 retail customers in the
State must also be designed to achieve lifetime peak
demand savings equal to the product of the incremental
annual peak demand savings goals defined by paragraph (2)
of subsection (b-16) and the minimum average savings life
defined by paragraph (3) of subsection (b-16) through

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implementation of energy efficiency measures. However, the
goals may be reduced if: (1) clear and convincing evidence
and independent analysis demonstrates that the expenditure
limits in subsection (m) of this Section preclude full
achievement of the goals; (2) each of the following
conditions are met: (A) the plan's analysis and forecasts
of the utility's ability to acquire energy savings
demonstrate by clear and convincing evidence and through
independent analysis that achievement of such goals is not
cost-effective; and (B) the amount of energy savings
achieved by the utility as determined by the independent
evaluator for the most recent year for which savings have
been evaluated preceding the plan filing was less than the
average annual amount of savings required to achieve the
goals for the applicable multi-year plan period; or (3)
changes in federal law, programs, or tariffs have a
significant and demonstrable impact on the cost of
delivering measures and programs. If there is not clear
and convincing evidence that achieving the savings goals
specified in subsection paragraph (b-16) of this Section
is possible both cost-effectively and within the
expenditure limits in subsection (m), such savings goals
shall not be reduced. Except as provided in subsection (m)
of this Section, annual savings goals during the
applicable multi-year plan period shall not be reduced to
amounts that are less than the maximum amount of annual

10400HB1700sam002 - 559 - LRB104 08228 AAS 38463 a
savings that is forecast to be cost-effectively achievable
during the applicable multi-year plan period. The
Commission shall review any proposed goal reduction as
part of its review and approval of the utility's proposed
plan.
Each utility's plan shall set forth the utility's
proposals to meet the energy efficiency standards identified
in subsection (b-5), (b-15), or (b-16), as applicable and as
such standards may have been modified under this subsection
(f), taking into account the unique circumstances of the
utility's service territory. For those plans commencing on
January 1, 2018, the Commission shall seek public comment on
the utility's plan and shall issue an order approving or
disapproving each plan no later than 105 days after June 1,
2017 (the effective date of Public Act 99-906). For those
plans commencing after December 31, 2021, the Commission shall
seek public comment on the utility's plan and shall issue an
order approving or disapproving each plan within 6 months
after its submission. If the Commission disapproves a plan,
the Commission shall, within 30 days, describe in detail the
reasons for the disapproval and describe a path by which the
utility may file a revised draft of the plan to address the
Commission's concerns satisfactorily. If the utility does not
refile with the Commission within 60 days, the utility shall
be subject to penalties at a rate of $100,000 per day until the
plan is filed. This process shall continue, and penalties

10400HB1700sam002 - 560 - LRB104 08228 AAS 38463 a
shall accrue, until the utility has successfully filed a
portfolio of energy efficiency and demand-response measures.
Penalties shall be deposited into the Energy Efficiency Trust
Fund.
(g) In submitting proposed plans and funding levels under
subsection (f) of this Section to meet the savings goals
identified in subsection (b-5), (b-15), or (b-16) of this
Section, as applicable, the utility shall:
(1) Demonstrate that its proposed energy efficiency
measures will achieve the applicable requirements that are
identified in subsection (b-5), (b-15), or (b-16) of this
Section, as modified by subsection (f) of this Section.
(2) (Blank).
(2.5) Demonstrate consideration of program options for
(A) advancing new building codes, appliance standards, and
municipal regulations governing existing and new building
efficiency improvements and (B) supporting efforts to
improve compliance with new building codes, appliance
standards and municipal regulations, as potentially
cost-effective means of acquiring energy savings to count
toward savings goals.
(3) Demonstrate that its overall portfolio of
measures, not including low-income programs described in
subsection (c) of this Section, is cost-effective using
the total resource cost test or complies with paragraphs
(1) through (3) of subsection (f) of this Section and

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represents a diverse cross-section of opportunities for
customers of all rate classes, other than those customers
described in subsection (l) of this Section, to
participate in the programs. Individual measures need not
be cost effective.
(3.5) Demonstrate that the utility's plan integrates
the delivery of energy efficiency programs with natural
gas efficiency programs, programs promoting distributed
solar, programs promoting demand response and other
efforts to address bill payment issues, including, but not
limited to, LIHEAP and the Percentage of Income Payment
Plan, to the extent such integration is practical and has
the potential to enhance customer engagement, minimize
market confusion, or reduce administrative costs.
(4) If the utility chooses, present a third-party
energy efficiency implementation program subject to the
following requirements:
(A) (blank);
(B) during 2018, the utility shall conduct a
solicitation process for purposes of requesting
proposals from third-party vendors for those
third-party energy efficiency programs to be offered
during one or more of the years commencing January 1,
2019, January 1, 2020, and January 1, 2021; for those
multi-year plans commencing on January 1, 2022 and
January 1, 2026, the utility shall conduct a

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solicitation process during 2021 and 2025,
respectively, for purposes of requesting proposals
from third-party vendors for those third-party energy
efficiency programs to be offered during one or more
years of the respective multi-year plan period; for
each solicitation process, the utility shall identify
the sector, technology, or geographical area for which
it is seeking requests for proposals; the solicitation
process must be either for programs that fill gaps in
the utility's program portfolio and for programs that
target low-income customers, business sectors,
building types, geographies, or other specific parts
of its customer base with initiatives that would be
more effective at reaching these customer segments
than the utilities' programs filed in its energy
efficiency plans;
(C) the utility shall propose the bidder
qualifications, performance measurement process, and
contract structure, which must include a performance
payment mechanism and general terms and conditions;
the proposed qualifications, process, and structure
shall be subject to Commission approval; and
(D) the utility shall retain an independent third
party to score the proposals received through the
solicitation process described in this paragraph (4),
rank them according to their cost per lifetime

10400HB1700sam002 - 563 - LRB104 08228 AAS 38463 a
kilowatt-hours saved, and assemble the portfolio of
third-party programs.
The electric utility shall recover all costs
associated with Commission-approved, third-party
administered programs regardless of the success of those
programs.
(4.5) Implement cost-effective demand-response
measures to reduce peak demand by 0.1% over the prior year
for eligible retail customers, as defined in Section
16-111.5 of this Act, and for customers that elect hourly
service from the utility pursuant to Section 16-107 of
this Act, provided those customers have not been declared
competitive. This requirement continues until December 31,
2026.
(5) Include a proposed or revised cost-recovery tariff
mechanism, as provided for under subsection (d) of this
Section, to fund the proposed energy efficiency and
demand-response measures and to ensure the recovery of the
prudently and reasonably incurred costs of
Commission-approved programs.
(6) Provide for an annual independent evaluation of
the performance of the cost-effectiveness of the utility's
portfolio of measures, as well as a full review of the
multi-year plan results of the broader net program impacts
and, to the extent practical, for adjustment of the
measures on a going-forward basis as a result of the

10400HB1700sam002 - 564 - LRB104 08228 AAS 38463 a
evaluations. The resources dedicated to evaluation shall
not exceed 3% of portfolio resources in any given year.
(7) For electric utilities that serve more than
3,000,000 retail customers in the State:
(A) Through December 31, 2026, provide for an
adjustment to the return on equity component of the
utility's weighted average cost of capital calculated
under subsection (d) of this Section:
(i) If the independent evaluator determines
that the utility achieved a cumulative persisting
annual savings that is less than the applicable
annual incremental goal, then the return on equity
component shall be reduced by a maximum of 200
basis points in the event that the utility
achieved no more than 75% of such goal. If the
utility achieved more than 75% of the applicable
annual incremental goal but less than 100% of such
goal, then the return on equity component shall be
reduced by 8 basis points for each percent by
which the utility failed to achieve the goal.
(ii) If the independent evaluator determines
that the utility achieved a cumulative persisting
annual savings that is more than the applicable
annual incremental goal, then the return on equity
component shall be increased by a maximum of 200
basis points in the event that the utility

10400HB1700sam002 - 565 - LRB104 08228 AAS 38463 a
achieved at least 125% of such goal. If the
utility achieved more than 100% of the applicable
annual incremental goal but less than 125% of such
goal, then the return on equity component shall be
increased by 8 basis points for each percent by
which the utility achieved above the goal. If the
applicable annual incremental goal was reduced
under paragraph (1) or (2) of subsection (f) of
this Section, then the following adjustments shall
be made to the calculations described in this item
(ii):
(aa) the calculation for determining
achievement that is at least 125% of the
applicable annual incremental goal shall use
the unreduced applicable annual incremental
goal to set the value; and
(bb) the calculation for determining
achievement that is less than 125% but more
than 100% of the applicable annual incremental
goal shall use the reduced applicable annual
incremental goal to set the value for 100%
achievement of the goal and shall use the
unreduced goal to set the value for 125%
achievement. The 8 basis point value shall
also be modified, as necessary, so that the
200 basis points are evenly apportioned among

10400HB1700sam002 - 566 - LRB104 08228 AAS 38463 a
each percentage point value between 100% and
125% achievement.
(B) (Blank).
(C) (Blank).
(7.5) For purposes of this Section, the term
"applicable annual incremental goal" means the difference
between the cumulative persisting annual savings goal for
the calendar year that is the subject of the independent
evaluator's determination and the cumulative persisting
annual savings goal for the immediately preceding calendar
year, as such goals are defined in subsections (b-5) and
(b-15) of this Section and as these goals may have been
modified as provided for under subsection (b-20) and
paragraphs (1) and (2) of subsection (f) of this Section.
Under subsections (b), (b-5), (b-10), and (b-15) of this
Section, a utility must first replace energy savings from
measures that have expired before any progress towards
achievement of its applicable annual incremental goal may
be counted. Savings may expire because measures installed
in previous years have reached the end of their lives,
because measures installed in previous years are producing
lower savings in the current year than in the previous
year, or for other reasons identified by independent
evaluators. Notwithstanding anything else set forth in
this Section, the difference between the actual annual
incremental savings achieved in any given year, including

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the replacement of energy savings that have expired, and
the applicable annual incremental goal shall not affect
adjustments to the return on equity for subsequent
calendar years under this subsection (g).
In this Section, "applicable annual total savings
requirement" means the total amount of new annual savings
that the utility must achieve in any given year to achieve
the applicable annual incremental goal. This is equal to
the applicable annual incremental goal plus the total new
annual savings that are required to replace savings that
expired in or at the end of the previous year.
(8) For electric utilities that serve less than
3,000,000 retail customers but more than 500,000 retail
customers in the State:
(A) Through December 31, 2026, the applicable
annual incremental goal shall be compared to the
annual incremental savings as determined by the
independent evaluator.
(i) The return on equity component shall be
reduced by 8 basis points for each percent by
which the utility did not achieve 84.4% of the
applicable annual incremental goal.
(ii) The return on equity component shall be
increased by 8 basis points for each percent by
which the utility exceeded 100% of the applicable
annual incremental goal.

10400HB1700sam002 - 568 - LRB104 08228 AAS 38463 a
(iii) The return on equity component shall not
be increased or decreased if the annual
incremental savings as determined by the
independent evaluator is greater than 84.4% of the
applicable annual incremental goal and less than
100% of the applicable annual incremental goal.
(iv) The return on equity component shall not
be increased or decreased by an amount greater
than 200 basis points pursuant to this
subparagraph (A).
(B) (Blank).
(C) (Blank).
(D) (Blank).
(8.5) Beginning January 1, 2027, a utility that serves
greater than 500,000 retail customers in the State shall
have the utility's return on equity modified for
performance on the utility's energy savings and peak
demand savings goals as follows:
(A) The return on equity for a utility that serves
more than 3,000,000 retail customers in the State may
be adjusted up or down by a maximum of 200 basis points
for its performance relative to the product of its
incremental annual energy savings goal and average
energy savings life. The return on equity for a
utility that serves less than 3,000,000 retail
customers but more than 500,000 retail customers in

10400HB1700sam002 - 569 - LRB104 08228 AAS 38463 a
the State may be adjusted up or down by a maximum of
100 basis points for its performance relative to the
product of its incremental annual energy savings goal
and average energy savings life and a maximum of 100
basis points for its performance relative to the
product of its incremental annual coincident peak
demand savings goal and average peak demand savings
life.
(B) A utility's performance on its savings goals
shall be established by comparing the actual lifetime
energy savings, and the actual lifetime coincident
peak demand savings if a utility serves less than
3,000,000 retail customers but more than 500,000
retail customers in the State, achieved from
efficiency measures installed in a given year to the
product of the incremental annual goals established in
paragraphs (1) and (2) of subsection (b-16) and the
minimum average savings lives established in paragraph
(3) of subsection (b-16), as modified, if applicable,
by the Commission under paragraph (4) of subsection
(f) of this Section. For the purposes of this
paragraph (8.5), "lifetime energy savings" means the
total incremental savings that installed efficiency
measures are projected to produce, relative to what
would have occurred absent to the utility's efficiency
programs, over the useful lives of the measures.

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Performance on the energy savings goal, and coincident
peak demand savings if a utility serves less than
3,000,000 retail customers but more than 500,000
retail customers in the State, shall be assessed
separately, such that it is possible to earn penalties
on both, earn bonuses on both, or earn a bonus for
performance on one goal and a penalty on the other.
(C) No bonus shall be earned if a utility does not
achieve greater than 100% of an approved goal. The
maximum bonus for a goal shall be earned if the utility
achieves 125% of the unmodified goal. For a utility
that serves less than 3,000,000 retail customers but
more than 500,000 retail customers in the State, the
bonus earned for achieving more than 100% of an
approved goal but less than 125% of the unmodified
goal shall be linearly interpolated. For a utility
with more than 3,000,000 retail customers, the maximum
bonus for a goal shall be earned if the utility
achieves 125% of the unmodified goal. For a utility
with more than 3,000,000 retail customers, the bonus
earned for achieving more than 100% of an approved
goal but less than 125% of the unmodified goal shall be
linearly interpolated.
(D) For utilities with greater than 3,000,000
retail customers, the return on equity shall be
unmodified due to performance on an individual goal

10400HB1700sam002 - 571 - LRB104 08228 AAS 38463 a
only if the utility achieves exactly 100% of the goal.
For utilities with more than 500,000 but fewer than
3,000,000 retail customers, the return on equity shall
be unmodified for achieving between 85% and 100% of
the goal.
(E) Penalties may be earned for falling short of
goals, with the magnitude of any penalty being a
function of both the size of the utility and whether
goals established in subsection (b-16) are modified by
the Commission under paragraph (4) of subsection (f)
of this Section, as follows:
(i) If the savings goals specified in
subsection (b-16) of this Section are unmodified,
a utility with more than 3,000,000 retail
customers shall earn the maximum penalty allocated
to a goal for achieving 75% or less of the goal.
The penalty for achieving greater than 75% but
less than 100% of the goal shall be linearly
interpolated.
(ii) If the savings goals specified in
subsection (b-16) of this Section are unmodified,
a utility with more than 500,000 but fewer than
3,000,000 retail customers shall earn the maximum
penalty allocated to a goal for achieving at least
33.3 percentage points less than the bottom end of
the deadband specified in subparagraph (D) of this

10400HB1700sam002 - 572 - LRB104 08228 AAS 38463 a
paragraph (8.5). The penalty for achieving less
than the bottom end of the deadband and greater
than 33.3 percentage points less than the bottom
end of the deadband shall be linearly
interpolated.
(iii) If either the energy or peak demand
savings goals specified in subsection (b-16) are
reduced under paragraph (3) or (4) of subsection
(f) of this Section, the maximum penalty allocated
to a goal shall be earned if the utility achieves
80% or less of the modified goal. The penalty for
achieving more than 80% but less than 100% of a
modified goal shall be linearly interpolated.
(9) The utility shall submit the energy savings data
to the independent evaluator no later than 30 days after
the close of the plan year. The independent evaluator
shall determine the cumulative persisting annual savings
and annual incremental savings for a given plan year, as
well as an estimate of job impacts and other macroeconomic
impacts of the efficiency programs for that year, no later
than 120 days after the close of the plan year. The utility
shall submit an informational filing to the Commission no
later than 160 days after the close of the plan year that
attaches the independent evaluator's final report
identifying the cumulative persisting annual savings for
the year and calculates, under paragraph (7) or (8) of

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this subsection (g), as applicable, any resulting change
to the utility's return on equity component of the
weighted average cost of capital applicable to the next
plan year beginning with the January monthly billing
period and extending through the December monthly billing
period. However, if the utility recovers the costs
incurred under this Section under paragraphs (2) and (3)
of subsection (d) of this Section, then the utility shall
not be required to submit such informational filing, and
shall instead submit the information that would otherwise
be included in the informational filing as part of its
filing under paragraph (3) of such subsection (d) that is
due on or before June 1 of each year.
For those utilities that must submit the informational
filing, the Commission may, on its own motion or by
petition, initiate an investigation of such filing,
provided, however, that the utility's proposed return on
equity calculation shall be deemed the final, approved
calculation on December 15 of the year in which it is filed
unless the Commission enters an order on or before
December 15, after notice and hearing, that modifies such
calculation consistent with this Section.
The adjustments to the return on equity component
described in paragraphs (7) and (8) of this subsection (g)
shall be applied as described in such paragraphs through a
separate tariff mechanism, which shall be filed by the

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utility under subsections (f) and (g) of this Section.
(9.5) The utility must demonstrate how it will ensure
that program implementation contractors and energy
efficiency installation vendors will promote workforce
equity and quality jobs. For all construction,
installation, or other related services procured under
this Section, an electric utility must:
(A) award a bid preference of 2% to a contractor if
the contractor certifies under oath that the
contractor's primary place of business is located
within the utility's service area; and
(B) award a bid preference of 2% to a contractor if
the contractor certifies under oath that at least 85%
of the workforce to be utilized for such construction,
installation, or other related services reside in the
utility's service area.
(9.6) Utilities shall collect data necessary to ensure
compliance with paragraph (9.5) no less than quarterly and
shall communicate progress toward compliance with
paragraph (9.5) to program implementation contractors and
energy efficiency installation vendors no less than
quarterly. Utilities shall work with relevant vendors,
providing education, training, and other resources needed
to ensure compliance and, where necessary, adjusting or
terminating work with vendors that cannot assist with
compliance.

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

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

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

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reconciles the moneys collected under its automatic adjustment
clause tariff with the costs incurred during the period
beginning June 1, 2016 and ending on the date that the electric
utility's automatic adjustment clause tariff was cancelled. In
the event the reconciliation reflects an under-collection, the
utility shall recover the costs as specified in this
subsection (k). If the reconciliation reflects an
over-collection, the utility shall apply the amount of such
over-collection as a one-time credit to retail customers'
bills.
(l) For the calendar years covered by a multi-year plan
commencing after December 31, 2017, subsections (a) through
(j) of this Section do not apply to eligible large private
energy customers that have chosen to opt out of multi-year
plans consistent with this subsection (1).
(1) For purposes of this subsection (l), "eligible
large private energy customer" means any retail customers,
except for federal, State, municipal, and other public
customers, of an electric utility that serves more than
3,000,000 retail customers, except for federal, State,
municipal and other public customers, in the State and
whose total highest 30 minute demand was more than 10,000
kilowatts, or any retail customers of an electric utility
that serves less than 3,000,000 retail customers but more
than 500,000 retail customers in the State and whose total
highest 15 minute demand was more than 10,000 kilowatts.

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For purposes of this subsection (l), "retail customer" has
the meaning set forth in Section 16-102 of this Act.
However, for a business entity with multiple sites located
in the State, where at least one of those sites qualifies
as an eligible large private energy customer, then any of
that business entity's sites, properly identified on a
form for notice, shall be considered eligible large
private energy customers for the purposes of this
subsection (l). A determination of whether this subsection
is applicable to a customer shall be made for each
multi-year plan beginning after December 31, 2017. The
criteria for determining whether this subsection (l) is
applicable to a retail customer shall be based on the 12
consecutive billing periods prior to the start of the
first year of each such multi-year plan.
(2) Within 45 days after September 15, 2021 (the
effective date of Public Act 102-662), the Commission
shall prescribe the form for notice required for opting
out of energy efficiency programs. The notice must be
submitted to the retail electric utility 12 months before
the next energy efficiency planning cycle. However, within
120 days after the Commission's initial issuance of the
form for notice, eligible large private energy customers
may submit a form for notice to an electric utility. The
form for notice for opting out of energy efficiency
programs shall include all of the following:

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

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

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requested plan cycle. An eligible large private energy
customer must also request to opt out for future energy
plan cycles, otherwise the customer will be included in
the future energy plan cycle.
(m) Notwithstanding the requirements of this Section, as
part of a proceeding to approve a multi-year plan under
subsections (f) and (g) of this Section if the multi-year plan
has been designed to maximize savings, but does not meet the
cost cap limitations of this Section, the Commission shall
reduce the amount of energy efficiency measures implemented
for any single year, and whose costs are recovered under
subsection (d) of this Section, by an amount necessary to
limit the estimated average net increase due to the cost of the
measures to no more than
(1) 3.5% for each of the 4 years beginning January 1,
2018,
(2) (blank),
(3) 4% for each of the 4 years beginning January 1,
2022,
(3.5) 4.25% for 2026,
(4) 4.25% for electric utilities that serve more than
3,000,000 retail customers in the State, and 4.21% for
2027, 5.25% for 2028, and 6.06% for 2029 for electric
utilities with less than 3,000,000 retail customers but
more than 500,000 retail customers in the State, for the 3
years beginning January 1, 2027, and

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(5) the percentage specified in paragraph (4)
applicable to 2029 plus an increase sufficient to account
for the rate of inflation between January 1, 2027 and
January 1 of the first year of each subsequent 4-year plan
cycle,
of the average amount paid per kilowatthour by residential
eligible retail customers during calendar year 2015 for plans
in effect through 2026 and during calendar year 2023 for plans
commencing in 2027 and thereafter. An electric utility may
plan to spend up to 10% more in any year during an applicable
multi-year plan period, including any transition period
authorized under paragraph (2.5) of subsection (f), to
cost-effectively achieve additional savings so long as the
average over the applicable multi-year plan period, which
shall include any transition period, does not exceed the
percentages defined in items (1) through (5). To determine the
total amount that may be spent by an electric utility in any
single year, the applicable percentage of the average amount
paid per kilowatthour shall be multiplied by (i) the total
amount of energy delivered by such electric utility in the
calendar year 2015 for plans in effect through 2026, (ii) for
an electric utility that serves more than 3,000,000 retail
customers in the State, the average amount of energy delivered
by such electric utility in calendar years 2021 through 2023
for plans commencing in 2027 and thereafter, and (iii) for an
electric utility that serves less than 3,000,000 retail

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customers but more than 500,000 retail customers in the State,
the total amount of energy delivered by such electric utility
in the calendar year 2023 and during calendar year 2023 for
plans commencing in 2027 and thereafter, adjusted to reflect
the proportion of the utility's load attributable to customers
that have opted out of subsections (a) through (j) of this
Section under subsection (l) of this Section. For purposes of
this subsection (m), the amount paid per kilowatthour
includes, without limitation, estimated amounts paid for
supply, transmission, distribution, surcharges, and add-on
taxes. For purposes of this Section, "eligible retail
customers" shall have the meaning set forth in Section
16-111.5 of this Act. Once the Commission has approved a plan
under subsections (f) and (g) of this Section, no subsequent
rate impact determinations shall be made.
(n) A utility shall take advantage of the efficiencies
available through existing Illinois Home Weatherization
Assistance Program infrastructure and services, such as
enrollment, marketing, quality assurance and implementation,
which can reduce the need for similar services at a lower cost
than utility-only programs, subject to capacity constraints at
community action agencies, for both single-family and
multifamily weatherization services, to the extent Illinois
Home Weatherization Assistance Program community action
agencies provide multifamily services. A utility's plan shall
demonstrate that in formulating annual weatherization budgets,

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it has sought input and coordination with community action
agencies regarding agencies' capacity to expand and maximize
Illinois Home Weatherization Assistance Program delivery using
the ratepayer dollars collected under this Section.
(Source: P.A. 103-154, eff. 6-30-23; 103-613, eff. 7-1-24;
104-458, eff. 6-1-26.)
(220 ILCS 5/16-107.5)
(Text of Section before amendment by P.A. 104-458)
Sec. 16-107.5. Net electricity metering.
(a) The General Assembly finds and declares that a program
to provide net electricity metering, as defined in this
Section, for eligible customers can encourage private
investment in renewable energy resources, stimulate economic
growth, enhance the continued diversification of Illinois'
energy resource mix, and protect the Illinois environment.
Further, to achieve the goals of this Act that robust options
for customer-site distributed generation continue to thrive in
Illinois, the General Assembly finds that a predictable
transition must be ensured for customers between full net
metering at the retail electricity rate to the distribution
generation rebate described in Section 16-107.6.
(b) As used in this Section, (i) "community renewable
generation project" shall have the meaning set forth in
Section 1-10 of the Illinois Power Agency Act; (ii) "eligible
customer" means a retail customer that owns, hosts, or

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

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for a period of time for use at a later time, including, but
not limited to, electrochemical, thermal, and
electromechanical technologies, and may be interconnected
behind the customer's meter or interconnected behind its own
meter; and (ix) "future electrical requirements" means modeled
electrical requirements upon occupation of a new or vacant
property, and other reasonable expectations of future
electrical use, as well as, for occupied properties, a
reasonable approximation of the annual load of 2 electric
vehicles and, for non-electric heating customers, a reasonable
approximation of the incremental electric load associated with
fuel switching. The approximations shall be applied to the
appropriate net metering tariff and do not need to be unique to
each individual eligible customer. The utility shall submit
these approximations to the Commission for review,
modification, and approval.
(c) A net metering facility shall be equipped with
metering equipment that can measure the flow of electricity in
both directions at the same rate.
(1) For eligible customers whose electric service has
not been declared competitive pursuant to Section 16-113
of this Act as of July 1, 2011 and whose electric delivery
service is provided and measured on a kilowatt-hour basis
and electric supply service is not provided based on
hourly pricing, this shall typically be accomplished
through use of a single, bi-directional meter. If the

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

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Act, the electricity provider may arrange for the local
electric utility or a meter service provider to install
and maintain metering equipment capable of measuring the
flow of electricity both into and out of the customer's
facility at the same rate and ratio, typically through the
use of a dual channel meter. If the eligible customer's
existing electric revenue meter does not meet this
requirement, then the costs of installing such equipment
shall be paid for by the customer.
(d) An electricity provider shall measure and charge or
credit for the net electricity supplied to eligible customers
or provided by eligible customers whose electric service has
not been declared competitive pursuant to Section 16-113 of
this Act as of July 1, 2011 and whose electric delivery service
is provided and measured on a kilowatt-hour basis and electric
supply service is not provided based on hourly pricing in the
following manner:
(1) If the amount of electricity used by the customer
during the billing period exceeds the amount of
electricity produced by the customer, the electricity
provider shall charge the customer for the net electricity
supplied to and used by the customer as provided in
subsection (e-5) of this Section.
(2) If the amount of electricity produced by a
customer during the billing period exceeds the amount of
electricity used by the customer during that billing

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

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amount of electricity produced by the customer, the
electricity provider shall charge the customer for the net
electricity supplied to and used by the customer according
to the terms of the contract or tariff to which the same
customer would be assigned to or be eligible for if the
customer was not a net metering customer.
(2) If the amount of electricity produced by a
customer during any hourly period or time-of-use period
exceeds the amount of electricity used by the customer
during that hourly period or time-of-use period, the
energy provider shall apply a credit for the net
kilowatt-hours produced in such period. The credit shall
consist of an energy credit and a delivery service credit.
The energy credit shall be valued at the same price per
kilowatt-hour as the electric service provider would
charge for kilowatt-hour energy sales during that same
hourly period or time-of-use period. The delivery credit
shall be equal to the net kilowatt-hours produced in such
hourly period or time-of-use period times a credit that
reflects all kilowatt-hour based charges in the customer's
electric service rate, excluding energy charges.
(e) An electricity provider shall measure and charge or
credit for the net electricity supplied to eligible customers
whose electric service has not been declared competitive
pursuant to Section 16-113 of this Act as of July 1, 2011 and
whose electric delivery service is provided and measured on a

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kilowatt demand basis and electric supply service is not
provided based on hourly pricing in the following manner:
(1) If the amount of electricity used by the customer
during the billing period exceeds the amount of
electricity produced by the customer, then the electricity
provider shall charge the customer for the net electricity
supplied to and used by the customer as provided in
subsection (e-5) of this Section. The customer shall
remain responsible for all taxes, fees, and utility
delivery charges that would otherwise be applicable to the
net amount of electricity used by the customer.
(2) If the amount of electricity produced by a
customer during the billing period exceeds the amount of
electricity used by the customer during that billing
period, then the electricity provider supplying that
customer shall apply a 1:1 kilowatt-hour credit that
reflects the kilowatt-hour based charges in the customer's
electric service rate to a subsequent bill for service to
the customer for the net electricity supplied to the
electricity provider. The electricity provider shall
continue to carry over any excess kilowatt-hour credits
earned and apply those credits to subsequent billing
periods to offset any customer-generator consumption in
those billing periods until all credits are used or until
the end of the annualized period.
(3) At the end of the year or annualized over the

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period that service is supplied by means of net metering,
or in the event that the retail customer terminates
service with the electricity provider prior to the end of
the year or the annualized period, any remaining credits
in the customer's account shall expire.
(e-5) An electricity provider shall provide electric
service to eligible customers who utilize net metering at
non-discriminatory rates that are identical, with respect to
rate structure, retail rate components, and any monthly
charges, to the rates that the customer would be charged if not
a net metering customer. An electricity provider shall not
charge net metering customers any fee or charge or require
additional equipment, insurance, or any other requirements not
specifically authorized by interconnection standards
authorized by the Commission, unless the fee, charge, or other
requirement would apply to other similarly situated customers
who are not net metering customers. The customer will remain
responsible for all taxes, fees, and utility delivery charges
that would otherwise be applicable to the net amount of
electricity used by the customer. Subsections (c) through (e)
of this Section shall not be construed to prevent an
arms-length agreement between an electricity provider and an
eligible customer that sets forth different prices, terms, and
conditions for the provision of net metering service,
including, but not limited to, the provision of the
appropriate metering equipment for non-residential customers.

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(f) Notwithstanding the requirements of subsections (c)
through (e-5) of this Section, an electricity provider must
require dual-channel metering for customers operating eligible
renewable electrical generating facilities to whom the
provisions of neither subsection (d), (d-5), nor (e) of this
Section apply. In such cases, electricity charges and credits
shall be determined as follows:
(1) The electricity provider shall assess and the
customer remains responsible for all taxes, fees, and
utility delivery charges that would otherwise be
applicable to the gross amount of kilowatt-hours supplied
to the eligible customer by the electricity provider.
(2) Each month that service is supplied by means of
dual-channel metering, the electricity provider shall
compensate the eligible customer for any excess
kilowatt-hour credits at the electricity provider's
avoided cost of electricity supply over the monthly period
or as otherwise specified by the terms of a power-purchase
agreement negotiated between the customer and electricity
provider.
(3) For all eligible net metering customers taking
service from an electricity provider under contracts or
tariffs employing hourly or time-of-use rates, any monthly
consumption of electricity shall be calculated according
to the terms of the contract or tariff to which the same
customer would be assigned to or be eligible for if the

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customer was not a net metering customer. When those same
customer-generators are net generators during any discrete
hourly or time-of-use period, the net kilowatt-hours
produced shall be valued at the same price per
kilowatt-hour as the electric service provider would
charge for retail kilowatt-hour sales during that same
time-of-use period.
(g) For purposes of federal and State laws providing
renewable energy credits or greenhouse gas credits, the
eligible customer shall be treated as owning and having title
to the renewable energy attributes, renewable energy credits,
and greenhouse gas emission credits related to any electricity
produced by the qualified generating unit. The electricity
provider may not condition participation in a net metering
program on the signing over of a customer's renewable energy
credits; provided, however, this subsection (g) shall not be
construed to prevent an arms-length agreement between an
electricity provider and an eligible customer that sets forth
the ownership or title of the credits.
(h) Within 120 days after the effective date of this
amendatory Act of the 95th General Assembly, the Commission
shall establish standards for net metering and, if the
Commission has not already acted on its own initiative,
standards for the interconnection of eligible renewable
generating equipment to the utility system. The
interconnection standards shall address any procedural

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barriers, delays, and administrative costs associated with the
interconnection of customer-generation while ensuring the
safety and reliability of the units and the electric utility
system. The Commission shall consider the Institute of
Electrical and Electronics Engineers (IEEE) Standard 1547 and
the issues of (i) reasonable and fair fees and costs, (ii)
clear timelines for major milestones in the interconnection
process, (iii) nondiscriminatory terms of agreement, and (iv)
any best practices for interconnection of distributed
generation.
(h-5) Within 90 days after the effective date of this
amendatory Act of the 102nd General Assembly, the Commission
shall:
(1) establish an Interconnection Working Group. The
working group shall include representatives from electric
utilities, developers of renewable electric generating
facilities, other industries that regularly apply for
interconnection with the electric utilities,
representatives of distributed generation customers, the
Commission Staff, and such other stakeholders with a
substantial interest in the topics addressed by the
Interconnection Working Group. The Interconnection Working
Group shall address at least the following issues:
(A) cost and best available technology for
interconnection and metering, including the
standardization and publication of standard costs;

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(B) transparency, accuracy and use of the
distribution interconnection queue and hosting
capacity maps;
(C) distribution system upgrade cost avoidance
through use of advanced inverter functions;
(D) predictability of the queue management process
and enforcement of timelines;
(E) benefits and challenges associated with group
studies and cost sharing;
(F) minimum requirements for application to the
interconnection process and throughout the
interconnection process to avoid queue clogging
behavior;
(G) process and customer service for
interconnecting customers adopting distributed energy
resources, including energy storage;
(H) options for metering distributed energy
resources, including energy storage;
(I) interconnection of new technologies, including
smart inverters and energy storage;
(J) collect, share, and examine data on Level 1
interconnection costs, including cost and type of
upgrades required for interconnection, and use this
data to inform the final standardized cost of Level 1
interconnection; and
(K) such other technical, policy, and tariff

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issues related to and affecting interconnection
performance and customer service as determined by the
Interconnection Working Group.
The Commission may create subcommittees of the
Interconnection Working Group to focus on specific issues
of importance, as appropriate. The Interconnection Working
Group shall report to the Commission on recommended
improvements to interconnection rules and tariffs and
policies as determined by the Interconnection Working
Group at least every 6 months. Such reports shall include
consensus recommendations of the Interconnection Working
Group and, if applicable, additional recommendations for
which consensus was not reached. The Commission shall use
the report from the Interconnection Working Group to
determine whether processes should be commenced to
formally codify or implement the recommendations;
(2) create or contract for an Ombudsman to resolve
interconnection disputes through non-binding arbitration.
The Ombudsman may be paid in full or in part through fees
levied on the initiators of the dispute; and
(3) determine a single standardized cost for Level 1
interconnections, which shall not exceed $200.
(i) All electricity providers shall begin to offer net
metering no later than April 1, 2008.
(j) An electricity provider shall provide net metering to
eligible customers according to subsections (d), (d-5), and

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(e). Eligible renewable electrical generating facilities for
which eligible customers registered for net metering before
January 1, 2025 shall continue to receive net metering
services according to subsections (d), (d-5), and (e) of this
Section for the lifetime of the system, regardless of whether
those retail customers change electricity providers or whether
the retail customer benefiting from the system changes. On and
after January 1, 2025, any eligible customer that applies for
net metering and previously would have qualified under
subsections (d), (d-5), or (e) shall only be eligible for net
metering as described in subsection (n).
(k) Each electricity provider shall maintain records and
report annually to the Commission the total number of net
metering customers served by the provider, as well as the
type, capacity, and energy sources of the generating systems
used by the net metering customers. Nothing in this Section
shall limit the ability of an electricity provider to request
the redaction of information deemed by the Commission to be
confidential business information.
(l)(1) Notwithstanding the definition of "eligible
customer" in item (ii) of subsection (b) of this Section, each
electricity provider shall allow net metering as set forth in
this subsection (l) and for the following projects, provided
that only electric utilities serving more than 200,000
customers as of January 1, 2021 shall provide net metering for
projects that are eligible for subparagraph (C) of this

10400HB1700sam002 - 600 - LRB104 08228 AAS 38463 a
paragraph (1) and have energized after the effective date of
this amendatory Act of the 102nd General Assembly:
(A) properties owned or leased by multiple customers
that contribute to the operation of an eligible renewable
electrical generating facility through an ownership or
leasehold interest of at least 200 watts in such facility,
such as a community-owned wind project, a community-owned
biomass project, a community-owned solar project, or a
community methane digester processing livestock waste from
multiple sources, provided that the facility is also
located within the utility's service territory;
(B) individual units, apartments, or properties
located in a single building that are owned or leased by
multiple customers and collectively served by a common
eligible renewable electrical generating facility, such as
an office or apartment building, a shopping center or
strip mall served by photovoltaic panels on the roof; and
(C) subscriptions to community renewable generation
projects, including community renewable generation
projects on the customer's side of the billing meter of a
host facility and partially used for the customer's own
load.
In addition, the nameplate capacity of the eligible
renewable electric generating facility that serves the demand
of the properties, units, or apartments identified in
paragraphs (1) and (2) of this subsection (l) shall not exceed

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5,000 kilowatts in nameplate capacity in total. Any eligible
renewable electrical generating facility or community
renewable generation project that is powered by photovoltaic
electric energy and installed after the effective date of this
amendatory Act of the 99th General Assembly must be installed
by a qualified person in compliance with the requirements of
Section 16-128A of the Public Utilities Act and any rules or
regulations adopted thereunder.
(2) Notwithstanding anything to the contrary, an
electricity provider shall provide credits for the electricity
produced by the projects described in paragraph (1) of this
subsection (l). The electricity provider shall provide credits
that include at least energy supply, capacity, transmission,
and, if applicable, the purchased energy adjustment on the
subscriber's monthly bill equal to the subscriber's share of
the production of electricity from the project, as determined
by paragraph (3) of this subsection (l). For customers with
transmission or capacity charges not charged on a
kilowatt-hour basis, the electricity provider shall prepare a
reasonable approximation of the kilowatt-hour equivalent value
and provide that value as a monetary credit. The electricity
provider shall submit these approximation methodologies to the
Commission for review, modification, and approval.
Notwithstanding anything to the contrary, customers on payment
plans or participating in budget billing programs shall have
credits applied on a monthly basis.

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(3) Notwithstanding anything to the contrary and
regardless of whether a subscriber to an eligible community
renewable generation project receives power and energy service
from the electric utility or an alternative retail electric
supplier, for projects eligible under paragraph (C) of
subparagraph (1) of this subsection (l), electric utilities
serving more than 200,000 customers as of January 1, 2021
shall provide the monetary credits to a subscriber's
subsequent bill for the electricity produced by community
renewable generation projects. The electric utility shall
provide monetary credits to a subscriber's subsequent bill at
the utility's total price to compare equal to the subscriber's
share of the production of electricity from the project, as
determined by paragraph (5) of this subsection (l). For the
purposes of this subsection, "total price to compare" means
the rate or rates published by the Illinois Commerce
Commission for energy supply for eligible customers receiving
supply service from the electric utility, and shall include
energy, capacity, transmission, and the purchased energy
adjustment. Notwithstanding anything to the contrary,
customers on payment plans or participating in budget billing
programs shall have credits applied on a monthly basis. Any
applicable credit or reduction in load obligation from the
production of the community renewable generating projects
receiving a credit under this subsection shall be credited to
the electric utility to offset the cost of providing the

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credit. To the extent that the credit or load obligation
reduction does not completely offset the cost of providing the
credit to subscribers of community renewable generation
projects as described in this subsection, the electric utility
may recover the remaining costs through its Multi-Year Rate
Plan. All electric utilities serving 200,000 or fewer
customers as of January 1, 2021 shall only provide the
monetary credits to a subscriber's subsequent bill for the
electricity produced by community renewable generation
projects if the subscriber receives power and energy service
from the electric utility. Alternative retail electric
suppliers providing power and energy service to a subscriber
located within the service territory of an electric utility
not subject to Sections 16-108.18 and 16-118 shall provide the
monetary credits to the subscriber's subsequent bill for the
electricity produced by community renewable generation
projects.
(4) If requested by the owner or operator of a community
renewable generating project, an electric utility serving more
than 200,000 customers as of January 1, 2021 shall enter into a
net crediting agreement with the owner or operator to include
a subscriber's subscription fee on the subscriber's monthly
electric bill and provide the subscriber with a net credit
equivalent to the total bill credit value for that generation
period minus the subscription fee, provided the subscription
fee is structured as a fixed percentage of bill credit value.

10400HB1700sam002 - 604 - LRB104 08228 AAS 38463 a
The net crediting agreement shall set forth payment terms from
the electric utility to the owner or operator of the community
renewable generating project, and the electric utility may
charge a net crediting fee to the owner or operator of a
community renewable generating project that may not exceed 2%
of the bill credit value. Notwithstanding anything to the
contrary, an electric utility serving 200,000 customers or
fewer as of January 1, 2021 shall not be obligated to enter
into a net crediting agreement with the owner or operator of a
community renewable generating project.
(5) For the purposes of facilitating net metering, the
owner or operator of the eligible renewable electrical
generating facility or community renewable generation project
shall be responsible for determining the amount of the credit
that each customer or subscriber participating in a project
under this subsection (l) is to receive in the following
manner:
(A) The owner or operator shall, on a monthly basis,
provide to the electric utility the kilowatthours of
generation attributable to each of the utility's retail
customers and subscribers participating in projects under
this subsection (l) in accordance with the customer's or
subscriber's share of the eligible renewable electric
generating facility's or community renewable generation
project's output of power and energy for such month. The
owner or operator shall electronically transmit such

10400HB1700sam002 - 605 - LRB104 08228 AAS 38463 a
calculations and associated documentation to the electric
utility, in a format or method set forth in the applicable
tariff, on a monthly basis so that the electric utility
can reflect the monetary credits on customers' and
subscribers' electric utility bills. The electric utility
shall be permitted to revise its tariffs to implement the
provisions of this amendatory Act of the 102nd General
Assembly. The owner or operator shall separately provide
the electric utility with the documentation detailing the
calculations supporting the credit in the manner set forth
in the applicable tariff.
(B) For those participating customers and subscribers
who receive their energy supply from an alternative retail
electric supplier, the electric utility shall remit to the
applicable alternative retail electric supplier the
information provided under subparagraph (A) of this
paragraph (3) for such customers and subscribers in a
manner set forth in such alternative retail electric
supplier's net metering program, or as otherwise agreed
between the utility and the alternative retail electric
supplier. The alternative retail electric supplier shall
then submit to the utility the amount of the charges for
power and energy to be applied to such customers and
subscribers, including the amount of the credit associated
with net metering.
(C) A participating customer or subscriber may provide

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

10400HB1700sam002 - 607 - LRB104 08228 AAS 38463 a
and the retail customer in accordance with the prices, terms,
and conditions provided for in that contract. Either the
electricity provider or the customer may require compliance
with the prices, terms, and conditions of the contract.
(n) On and after January 1, 2025, the net metering
services described in subsections (d), (d-5), and (e) of this
Section shall no longer be offered, except as to those
eligible renewable electrical generating facilities for which
retail customers are receiving net metering service under
these subsections at the time the net metering services under
those subsections are no longer offered; those systems shall
continue to receive net metering services described in
subsections (d), (d-5), and (e) of this Section for the
lifetime of the system, regardless of if those retail
customers change electricity providers or whether the retail
customer benefiting from the system changes. The electric
utility serving more than 200,000 customers as of January 1,
2021 is responsible for ensuring the billing credits continue
without lapse for the lifetime of systems, as required in
subsection (o). Those retail customers that begin taking net
metering service after the date that net metering services are
no longer offered under such subsections shall be subject to
the provisions set forth in the following paragraphs (1)
through (3) of this subsection (n):
(1) An electricity provider shall charge or credit for
the net electricity supplied to eligible customers or

10400HB1700sam002 - 608 - LRB104 08228 AAS 38463 a
provided by eligible customers whose electric supply
service is not provided based on hourly pricing in the
following manner:
(A) If the amount of electricity used by the
customer during the monthly billing period exceeds the
amount of electricity produced by the customer, then
the electricity provider shall charge the customer for
the net kilowatt-hour based electricity charges
reflected in the customer's electric service rate
supplied to and used by the customer as provided in
paragraph (3) of this subsection (n).
(B) If the amount of electricity produced by a
customer during the monthly billing period exceeds the
amount of electricity used by the customer during that
billing period, then the electricity provider
supplying that customer shall apply a 1:1
kilowatt-hour energy or monetary credit kilowatt-hour
supply charges to the customer's subsequent bill. The
customer shall choose between 1:1 kilowatt-hour or
monetary credit at the time of application. For the
purposes of this subsection, "kilowatt-hour supply
charges" means the kilowatt-hour equivalent values for
energy, capacity, transmission, and the purchased
energy adjustment, if applicable. Notwithstanding
anything to the contrary, customers on payment plans
or participating in budget billing programs shall have

10400HB1700sam002 - 609 - LRB104 08228 AAS 38463 a
credits applied on a monthly basis. The electricity
provider shall continue to carry over any excess
kilowatt-hour or monetary energy credits earned and
apply those credits to subsequent billing periods. For
customers with transmission or capacity charges not
charged on a kilowatt-hour basis, the electricity
provider shall prepare a reasonable approximation of
the kilowatt-hour equivalent value and provide that
value as a monetary credit. The electricity provider
shall submit these approximation methodologies to the
Commission for review, modification, and approval.
(C) (Blank).
(2) An electricity provider shall charge or credit for
the net electricity supplied to eligible customers or
provided by eligible customers whose electric supply
service is provided based on hourly pricing in the
following manner:
(A) If the amount of electricity used by the
customer during any hourly period exceeds the amount
of electricity produced by the customer, then the
electricity provider shall charge the customer for the
net electricity supplied to and used by the customer
as provided in paragraph (3) of this subsection (n).
(B) If the amount of electricity produced by a
customer during any hourly period exceeds the amount
of electricity used by the customer during that hourly

10400HB1700sam002 - 610 - LRB104 08228 AAS 38463 a
period, the energy provider shall calculate an energy
credit for the net kilowatt-hours produced in such
period, and shall apply that credit as a monetary
credit to the customer's subsequent bill. The value of
the energy credit shall be calculated using the same
price per kilowatt-hour as the electric service
provider would charge for kilowatt-hour energy sales
during that same hourly period and shall also include
values for capacity and transmission. For customers
with transmission or capacity charges not charged on a
kilowatt-hour basis, the electricity provider shall
prepare a reasonable approximation of the
kilowatt-hour equivalent value and provide that value
as a monetary credit. The electricity provider shall
submit these approximation methodologies to the
Commission for review, modification, and approval.
Notwithstanding anything to the contrary, customers on
payment plans or participating in budget billing
programs shall have credits applied on a monthly
basis.
(3) An electricity provider shall provide electric
service to eligible customers who utilize net metering at
non-discriminatory rates that are identical, with respect
to rate structure, retail rate components, and any monthly
charges, to the rates that the customer would be charged
if not a net metering customer. An electricity provider

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shall charge the customer for the net electricity supplied
to and used by the customer according to the terms of the
contract or tariff to which the same customer would be
assigned or be eligible for if the customer was not a net
metering customer. An electricity provider shall not
charge net metering customers any fee or charge or require
additional equipment, insurance, or any other requirements
not specifically authorized by interconnection standards
authorized by the Commission, unless the fee, charge, or
other requirement would apply to other similarly situated
customers who are not net metering customers. The customer
remains responsible for the gross amount of delivery
services charges, supply-related charges that are kilowatt
based, and all taxes and fees related to such charges. The
customer also remains responsible for all taxes and fees
that would otherwise be applicable to the net amount of
electricity used by the customer. Paragraphs (1) and (2)
of this subsection (n) shall not be construed to prevent
an arms-length agreement between an electricity provider
and an eligible customer that sets forth different prices,
terms, and conditions for the provision of net metering
service, including, but not limited to, the provision of
the appropriate metering equipment for non-residential
customers. Nothing in this paragraph (3) shall be
interpreted to mandate that a utility that is only
required to provide delivery services to a given customer

10400HB1700sam002 - 612 - LRB104 08228 AAS 38463 a
must also sell electricity to such customer.
(o) Within 90 days after the effective date of this
amendatory Act of the 102nd General Assembly, each electric
utility subject to this Section shall file a tariff, which
shall, consistent with the provisions of this Section, propose
the terms and conditions under which a customer may
participate in net metering. The tariff for electric utilities
serving more than 200,000 customers as of January 1, 2021
shall also provide a streamlined and transparent bill
crediting system for net metering to be managed by the
electric utilities. The terms and conditions shall include,
but are not limited to, that an electric utility shall manage
and maintain billing of net metering credits and charges
regardless of if the eligible customer takes net metering
under an electric utility or alternative retail electric
supplier. The electric utility serving more than 200,000
customers as of January 1, 2021 shall process and approve all
net metering applications, even if an eligible customer is
served by an alternative retail electric supplier; and the
utility shall forward application approval to the appropriate
alternative retail electric supplier. Eligibility for net
metering shall remain with the owner of the utility billing
address such that, if an eligible renewable electrical
generating facility changes ownership, the net metering
eligibility transfers to the new owner. The electric utility
serving more than 200,000 customers as of January 1, 2021

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

10400HB1700sam002 - 614 - LRB104 08228 AAS 38463 a
billing transfers immediately if an eligible customer switches
from an electric utility to alternative retail electric
supplier or vice versa, and net metering billing transfers
between ownership of a valid billing address.
(Source: P.A. 102-662, eff. 9-15-21.)
(Text of Section after amendment by P.A. 104-458)
Sec. 16-107.5. Net electricity metering.
(a) The General Assembly finds and declares that a program
to provide net electricity metering, as defined in this
Section, for eligible customers can encourage private
investment in renewable energy resources, stimulate economic
growth, enhance the continued diversification of Illinois'
energy resource mix, and protect the Illinois environment.
Further, to achieve the goals of this Act that robust options
for customer-site distributed generation and storage continue
to thrive in Illinois, the General Assembly finds that a
predictable transition must be ensured for customers between
full net metering at the retail electricity rate to the
distribution generation rebate described in Section 16-107.6.
(b) As used in this Section:
(i) "Community renewable generation project" shall
have the meaning set forth in Section 1-10 of the Illinois
Power Agency Act.
(ii) "Eligible customer" means a retail customer that
owns, hosts, or operates, including any third-party owned

10400HB1700sam002 - 615 - LRB104 08228 AAS 38463 a
systems, a solar, wind, or other eligible renewable
electrical generating facility or an eligible storage
device that is located on the customer's premises or
customer's side of the billing meter and is intended
primarily to offset the customer's own current or future
electrical requirements.
(iii) "Electricity provider" means an electric utility
or alternative retail electric supplier.
(iv) "Eligible renewable electrical generating
facility" means a generator, which may include the
colocation of an energy storage system, that is
interconnected under rules adopted by the Commission and
is powered by solar electric energy, wind, dedicated crops
grown for electricity generation, agricultural residues,
untreated and unadulterated wood waste, livestock manure,
anaerobic digestion of livestock or food processing waste,
fuel cells or microturbines powered by renewable fuels, or
hydroelectric energy.
(v) "Net electricity metering" (or "net metering")
means the measurement, during the billing period
applicable to an eligible customer, of the net amount of
electricity supplied by an electricity provider to the
customer or provided to the electricity provider by the
customer or subscriber.
(vi) "Subscriber" shall have the meaning as set forth
in Section 1-10 of the Illinois Power Agency Act.

10400HB1700sam002 - 616 - LRB104 08228 AAS 38463 a
(vii) "Subscription" shall have the meaning set forth
in Section 1-10 of the Illinois Power Agency Act.
(viii) "Energy storage system" means commercially
available technology that is capable of absorbing energy
and storing it for a period of time for use at a later
time, including, but not limited to, electrochemical,
thermal, and electromechanical technologies, and may be
interconnected behind the customer's meter or
interconnected behind its own meter.
(ix) "Future electrical requirements" means modeled
electrical requirements upon occupation of a new or vacant
property, and other reasonable expectations of future
electrical use, as well as, for occupied properties, a
reasonable approximation of the annual load of 2 electric
vehicles and, for non-electric heating customers, a
reasonable approximation of the incremental electric load
associated with fuel switching. The approximations shall
be applied to the appropriate net metering tariff and do
not need to be unique to each individual eligible
customer. The utility shall submit these approximations to
the Commission for review, modification, and approval.
(x) "Vehicle storage system" means a vehicle that when
connected to an electric utility's distribution system is
capable of being an energy storage system, as defined in
Section 16-107.6.
(c) A net metering facility shall be equipped with

10400HB1700sam002 - 617 - LRB104 08228 AAS 38463 a
metering equipment that can measure the flow of electricity in
both directions at the same rate.
(1) For eligible customers whose electric service has
not been declared competitive pursuant to Section 16-113
of this Act as of July 1, 2011 and whose electric delivery
service is provided and measured on a kilowatt-hour basis
and electric supply service is not provided based on
hourly pricing, this shall typically be accomplished
through use of a single, bi-directional meter. If the
eligible customer's existing electric revenue meter does
not meet this requirement, the electricity provider shall
arrange for the local electric utility or a meter service
provider to install and maintain a new revenue meter at
the electricity provider's expense, which may be the smart
meter described by subsection (b) of Section 16-108.5 of
this Act.
(2) For eligible customers whose electric service has
not been declared competitive pursuant to Section 16-113
of this Act as of July 1, 2011 and whose electric delivery
service is provided and measured on a kilowatt demand
basis and electric supply service is not provided based on
hourly pricing, this shall typically be accomplished
through use of a dual channel meter capable of measuring
the flow of electricity both into and out of the
customer's facility at the same rate and ratio. If such
customer's existing electric revenue meter does not meet

10400HB1700sam002 - 618 - LRB104 08228 AAS 38463 a
this requirement, then the electricity provider shall
arrange for the local electric utility or a meter service
provider to install and maintain a new revenue meter at
the electricity provider's expense, which may be the smart
meter described by subsection (b) of Section 16-108.5 of
this Act.
(3) For all other eligible customers, until such time
as the local electric utility installs a smart meter, as
described by subsection (b) of Section 16-108.5 of this
Act, the electricity provider may arrange for the local
electric utility or a meter service provider to install
and maintain metering equipment capable of measuring the
flow of electricity both into and out of the customer's
facility at the same rate and ratio, typically through the
use of a dual channel meter. If the eligible customer's
existing electric revenue meter does not meet this
requirement, then the costs of installing such equipment
shall be paid for by the customer.
(d) An electricity provider shall measure and charge or
credit for the net electricity supplied to eligible customers
or provided by eligible customers whose electric service has
not been declared competitive pursuant to Section 16-113 of
this Act as of July 1, 2011 and whose electric delivery service
is provided and measured on a kilowatt-hour basis and electric
supply service is not provided based on hourly pricing in the
following manner:

10400HB1700sam002 - 619 - LRB104 08228 AAS 38463 a
(1) If the amount of electricity used by the customer
during the billing period exceeds the amount of
electricity produced by the customer, the electricity
provider shall charge the customer for the net electricity
supplied to and used by the customer as provided in
subsection (e-5) of this Section.
(2) If the amount of electricity produced by a
customer during the billing period exceeds the amount of
electricity used by the customer during that billing
period, the electricity provider supplying that customer
shall apply a 1:1 kilowatt-hour credit to a subsequent
bill for service to the customer for the net electricity
supplied to the electricity provider. The electricity
provider shall continue to carry over any excess
kilowatt-hour credits earned and apply those credits to
subsequent billing periods to offset any
customer-generator consumption in those billing periods
until all credits are used or until the end of the
annualized period.
(3) At the end of the year or annualized over the
period that service is supplied by means of net metering,
or in the event that the retail customer terminates
service with the electricity provider prior to the end of
the year or the annualized period, any remaining credits
in the customer's account shall expire.
(d-5) An electricity provider shall measure and charge or

10400HB1700sam002 - 620 - LRB104 08228 AAS 38463 a
credit for the net electricity supplied to eligible customers
or provided by eligible customers whose electric service has
not been declared competitive pursuant to Section 16-113 of
this Act as of July 1, 2011 and whose electric delivery service
is provided and measured on a kilowatt-hour basis and electric
supply service is provided based on hourly pricing or
time-of-use rates in the following manner:
(1) If the amount of electricity used by the customer
during any hourly period or time-of-use period exceeds the
amount of electricity produced by the customer, the
electricity provider shall charge the customer for the net
electricity supplied to and used by the customer according
to the terms of the contract or tariff to which the same
customer would be assigned to or be eligible for if the
customer was not a net metering customer.
(2) If the amount of electricity produced by a
customer during any hourly period or time-of-use period
exceeds the amount of electricity used by the customer
during that hourly period or time-of-use period, the
energy provider shall apply a credit for the net
kilowatt-hours produced in such period. The credit shall
consist of an energy credit and a delivery service credit.
The energy credit shall be valued at the same price per
kilowatt-hour as the electric service provider would
charge for kilowatt-hour energy sales during that same
hourly period or time-of-use period. The delivery credit

10400HB1700sam002 - 621 - LRB104 08228 AAS 38463 a
shall be equal to the net kilowatt-hours produced in such
hourly period or time-of-use period times a credit that
reflects all kilowatt-hour based charges in the customer's
electric service rate, excluding energy charges.
(e) An electricity provider shall measure and charge or
credit for the net electricity supplied to eligible customers
whose electric service has not been declared competitive
pursuant to Section 16-113 of this Act as of July 1, 2011 and
whose electric delivery service is provided and measured on a
kilowatt demand basis and electric supply service is not
provided based on hourly pricing in the following manner:
(1) If the amount of electricity used by the customer
during the billing period exceeds the amount of
electricity produced by the customer, then the electricity
provider shall charge the customer for the net electricity
supplied to and used by the customer as provided in
subsection (e-5) of this Section. The customer shall
remain responsible for all taxes, fees, and utility
delivery charges that would otherwise be applicable to the
net amount of electricity used by the customer.
(2) If the amount of electricity produced by a
customer during the billing period exceeds the amount of
electricity used by the customer during that billing
period, then the electricity provider supplying that
customer shall apply a 1:1 kilowatt-hour credit that
reflects the kilowatt-hour based charges in the customer's

10400HB1700sam002 - 622 - LRB104 08228 AAS 38463 a
electric service rate to a subsequent bill for service to
the customer for the net electricity supplied to the
electricity provider. The electricity provider shall
continue to carry over any excess kilowatt-hour credits
earned and apply those credits to subsequent billing
periods to offset any customer-generator consumption in
those billing periods until all credits are used or until
the end of the annualized period.
(3) At the end of the year or annualized over the
period that service is supplied by means of net metering,
or in the event that the retail customer terminates
service with the electricity provider prior to the end of
the year or the annualized period, any remaining credits
in the customer's account shall expire.
(e-5) An electricity provider shall provide electric
service to eligible customers who utilize net metering at
non-discriminatory rates that are identical, with respect to
rate structure, retail rate components, and any monthly
charges, to the rates that the customer would be charged if not
a net metering customer. An electricity provider shall not
charge net metering customers any fee or charge or require
additional equipment, insurance, or any other requirements not
specifically authorized by interconnection standards
authorized by the Commission, unless the fee, charge, or other
requirement would apply to other similarly situated customers
who are not net metering customers. The customer will remain

10400HB1700sam002 - 623 - LRB104 08228 AAS 38463 a
responsible for all taxes, fees, and utility delivery charges
that would otherwise be applicable to the net amount of
electricity used by the customer. Subsections (c) through (e)
of this Section shall not be construed to prevent an
arms-length agreement between an electricity provider and an
eligible customer that sets forth different prices, terms, and
conditions for the provision of net metering service,
including, but not limited to, the provision of the
appropriate metering equipment for non-residential customers.
(f) Notwithstanding the requirements of subsections (c)
through (e-5) of this Section, an electricity provider must
require dual-channel metering for customers operating eligible
renewable electrical generating facilities to whom the
provisions of neither subsection (d), (d-5), nor (e) of this
Section apply. In such cases, electricity charges and credits
shall be determined as follows:
(1) The electricity provider shall assess and the
customer remains responsible for all taxes, fees, and
utility delivery charges that would otherwise be
applicable to the gross amount of kilowatt-hours supplied
to the eligible customer by the electricity provider.
(2) Each month that service is supplied by means of
dual-channel metering, the electricity provider shall
compensate the eligible customer for any excess
kilowatt-hour credits at the electricity provider's
avoided cost of electricity supply over the monthly period

10400HB1700sam002 - 624 - LRB104 08228 AAS 38463 a
or as otherwise specified by the terms of a power-purchase
agreement negotiated between the customer and electricity
provider.
(3) For all eligible net metering customers taking
service from an electricity provider under contracts or
tariffs employing hourly or time-of-use rates, any monthly
consumption of electricity shall be calculated according
to the terms of the contract or tariff to which the same
customer would be assigned to or be eligible for if the
customer was not a net metering customer. When those same
customer-generators are net generators during any discrete
hourly or time-of-use period, the net kilowatt-hours
produced shall be valued at the same price per
kilowatt-hour as the electric service provider would
charge for retail kilowatt-hour sales during that same
time-of-use period.
(g) For purposes of federal and State laws providing
renewable energy credits or greenhouse gas credits, the
eligible customer shall be treated as owning and having title
to the renewable energy attributes, renewable energy credits,
and greenhouse gas emission credits related to any electricity
produced by the qualified generating unit. The electricity
provider may not condition participation in a net metering
program on the signing over of a customer's renewable energy
credits; provided, however, this subsection (g) shall not be
construed to prevent an arms-length agreement between an

10400HB1700sam002 - 625 - LRB104 08228 AAS 38463 a
electricity provider and an eligible customer that sets forth
the ownership or title of the credits.
(h) Within 120 days after the effective date of this
amendatory Act of the 95th General Assembly, the Commission
shall establish standards for net metering and, if the
Commission has not already acted on its own initiative,
standards for the interconnection of eligible renewable
generating equipment to the utility system. The
interconnection standards shall address any procedural
barriers, delays, and administrative costs associated with the
interconnection of customer-generation while ensuring the
safety and reliability of the units and the electric utility
system. The Commission shall consider the Institute of
Electrical and Electronics Engineers (IEEE) Standard 1547 and
the issues of (i) reasonable and fair fees and costs, (ii)
clear timelines for major milestones in the interconnection
process, (iii) nondiscriminatory terms of agreement, and (iv)
any best practices for interconnection of distributed
generation.
(i) All electricity providers shall begin to offer net
metering no later than April 1, 2008.
(j) An electricity provider shall provide net metering to
eligible customers according to subsections (d), (d-5), and
(e). Eligible renewable electrical generating facilities for
which eligible customers registered for net metering before
January 1, 2025 shall continue to receive net metering

10400HB1700sam002 - 626 - LRB104 08228 AAS 38463 a
services according to subsections (d), (d-5), and (e) of this
Section for the lifetime of the system, regardless of whether
those retail customers change electricity providers or whether
the retail customer benefiting from the system changes. On and
after January 1, 2025, any eligible customer that applies for
net metering and previously would have qualified under
subsections (d), (d-5), or (e) shall only be eligible for net
metering as described in subsection (n).
(k) Each electricity provider shall maintain records and
report annually to the Commission the total number of net
metering customers served by the provider, as well as the
type, capacity, and energy sources of the generating systems
used by the net metering customers. Nothing in this Section
shall limit the ability of an electricity provider to request
the redaction of information deemed by the Commission to be
confidential business information.
(l)(1) Notwithstanding the definition of "eligible
customer" in item (ii) of subsection (b) of this Section, each
electricity provider shall allow net metering as set forth in
this subsection (l) and for the following projects, provided
that only electric utilities serving more than 200,000
customers as of January 1, 2021 shall provide net metering for
projects that are eligible for subparagraph (C) of this
paragraph (1) and have energized after the effective date of
this amendatory Act of the 102nd General Assembly:
(A) properties owned or leased by multiple customers

10400HB1700sam002 - 627 - LRB104 08228 AAS 38463 a
that contribute to the operation of an eligible renewable
electrical generating facility through an ownership or
leasehold interest of at least 200 watts in such facility,
such as a community-owned wind project, a community-owned
biomass project, a community-owned solar project, or a
community methane digester processing livestock waste from
multiple sources, provided that the facility is also
located within the utility's service territory;
(B) individual units, apartments, or properties
located in a single building that are owned or leased by
multiple customers and collectively served by a common
eligible renewable electrical generating facility, such as
an office or apartment building, a shopping center or
strip mall served by photovoltaic panels on the roof; and
(C) subscriptions to community renewable generation
projects, including community renewable generation
projects on the customer's side of the billing meter of a
host facility and partially used for the customer's own
load.
In addition, the nameplate capacity of the eligible
renewable electric generating facility that serves the demand
of the properties, units, or apartments identified in
paragraphs (1) and (2) of this subsection (l) shall not exceed
5,000 kilowatts in nameplate capacity in total. Any eligible
renewable electrical generating facility or community
renewable generation project that is powered by photovoltaic

10400HB1700sam002 - 628 - LRB104 08228 AAS 38463 a
electric energy and installed after the effective date of this
amendatory Act of the 99th General Assembly must be installed
by a qualified person in compliance with the requirements of
Section 16-128A of the Public Utilities Act and any rules or
regulations adopted thereunder.
(2) Notwithstanding anything to the contrary, an
electricity provider shall provide credits for the electricity
produced by the projects described in paragraph (1) of this
subsection (l). The electricity provider shall provide credits
that include at least energy supply, capacity, transmission,
and, if applicable, the purchased energy adjustment on the
subscriber's monthly bill equal to the subscriber's share of
the production of electricity from the project, as determined
by paragraph (3) of this subsection (l). For customers with
transmission or capacity charges not charged on a
kilowatt-hour basis, the electricity provider shall prepare a
reasonable approximation of the kilowatt-hour equivalent value
and provide that value as a monetary credit. The electricity
provider shall submit these approximation methodologies to the
Commission for review, modification, and approval.
Notwithstanding anything to the contrary, customers on payment
plans or participating in budget billing programs shall have
credits applied on a monthly basis.
(3) Notwithstanding anything to the contrary and
regardless of whether a subscriber to an eligible community
renewable generation project receives power and energy service

10400HB1700sam002 - 629 - LRB104 08228 AAS 38463 a
from the electric utility or an alternative retail electric
supplier, for projects eligible under paragraph (C) of
subparagraph (1) of this subsection (l), electric utilities
serving more than 200,000 customers as of January 1, 2021
shall provide the monetary credits to a subscriber's
subsequent bill for the electricity produced by community
renewable generation projects. The electric utility shall
provide monetary credits to a subscriber's subsequent bill at
the utility's total price to compare equal to the subscriber's
share of the production of electricity from the project, as
determined by paragraph (5) of this subsection (l). For the
purposes of this subsection, "total price to compare" means
the rate or rates published by the Illinois Commerce
Commission for energy supply for eligible customers receiving
supply service from the electric utility, and shall include
energy, capacity, transmission, and the purchased energy
adjustment. Notwithstanding anything to the contrary,
customers on payment plans or participating in budget billing
programs shall have credits applied on a monthly basis. Any
applicable credit or reduction in load obligation from the
production of the community renewable generating projects
receiving a credit under this subsection shall be credited to
the electric utility to offset the cost of providing the
credit. To the extent that the credit or load obligation
reduction does not completely offset the cost of providing the
credit to subscribers of community renewable generation

10400HB1700sam002 - 630 - LRB104 08228 AAS 38463 a
projects as described in this subsection, the electric utility
may recover the remaining costs through its Multi-Year Rate
Plan. All electric utilities serving 200,000 or fewer
customers as of January 1, 2021 shall only provide the
monetary credits to a subscriber's subsequent bill for the
electricity produced by community renewable generation
projects if the subscriber receives power and energy service
from the electric utility. Alternative retail electric
suppliers providing power and energy service to a subscriber
located within the service territory of an electric utility
not subject to Sections 16-108.18 and 16-118 shall provide the
monetary credits to the subscriber's subsequent bill for the
electricity produced by community renewable generation
projects.
(4) If requested by the owner or operator of a community
renewable generating project, an electric utility serving more
than 200,000 customers as of January 1, 2021 shall enter into a
net crediting agreement with the owner or operator to include
a subscriber's subscription fee on the subscriber's monthly
electric bill and provide the subscriber with a net credit
equivalent to the total bill credit value for that generation
period minus the subscription fee, provided the subscription
fee is structured as a fixed percentage of bill credit value.
The net crediting agreement shall set forth payment terms from
the electric utility to the owner or operator of the community
renewable generating project, and the electric utility may

10400HB1700sam002 - 631 - LRB104 08228 AAS 38463 a
charge a net crediting fee to the owner or operator of a
community renewable generating project that may not exceed 1%
of the subscription fee. Notwithstanding anything to the
contrary, an electric utility serving 200,000 customers or
fewer as of January 1, 2021 shall not be obligated to enter
into a net crediting agreement with the owner or operator of a
community renewable generating project. An electric utility
shall use the same net crediting format for subscribers on
payment plans and subscribers participating in budget billing
programs. For the purposes of this paragraph (4), "net
crediting" means a program offered by an electric utility
under which the electric utility, upon authorization by or on
behalf of a subscriber, remits the cash value of the
subscription fee to the owner or operator of the community
renewable generation facility without regard to whether the
subscriber has paid the subscriber's monthly electric bill and
places the cash value of the remaining bill credit on the
subscriber's bill.
(5) For the purposes of facilitating net metering, the
owner or operator of the eligible renewable electrical
generating facility or community renewable generation project
shall be responsible for determining the amount of the credit
that each customer or subscriber participating in a project
under this subsection (l) is to receive in the following
manner:
(A) The owner or operator shall, on a monthly basis,

10400HB1700sam002 - 632 - LRB104 08228 AAS 38463 a
provide to the electric utility the kilowatthours of
generation attributable to each of the utility's retail
customers and subscribers participating in projects under
this subsection (l) in accordance with the customer's or
subscriber's share of the eligible renewable electric
generating facility's or community renewable generation
project's output of power and energy for such month. The
owner or operator shall electronically transmit such
calculations and associated documentation to the electric
utility, in a format or method set forth in the applicable
tariff, on a monthly basis so that the electric utility
can reflect the monetary credits on customers' and
subscribers' electric utility bills. The electric utility
shall be permitted to revise its tariffs to implement the
provisions of this amendatory Act of the 102nd General
Assembly. The owner or operator shall separately provide
the electric utility with the documentation detailing the
calculations supporting the credit in the manner set forth
in the applicable tariff.
(B) For those participating customers and subscribers
who receive their energy supply from an alternative retail
electric supplier, the electric utility shall remit to the
applicable alternative retail electric supplier the
information provided under subparagraph (A) of this
paragraph (3) for such customers and subscribers in a
manner set forth in such alternative retail electric

10400HB1700sam002 - 633 - LRB104 08228 AAS 38463 a
supplier's net metering program, or as otherwise agreed
between the utility and the alternative retail electric
supplier. The alternative retail electric supplier shall
then submit to the utility the amount of the charges for
power and energy to be applied to such customers and
subscribers, including the amount of the credit associated
with net metering.
(C) A participating customer or subscriber may provide
authorization as required by applicable law that directs
the electric utility to submit information to the owner or
operator of the eligible renewable electrical generating
facility or community renewable generation project to
which the customer or subscriber has an ownership or
leasehold interest or a subscription. Such information
shall be limited to the components of the net metering
credit calculated under this subsection (l), including the
bill credit rate, total kilowatthours, and total monetary
credit value applied to the customer's or subscriber's
bill for the monthly billing period.
(l-5) Within 90 days after the effective date of this
amendatory Act of the 102nd General Assembly, each electric
utility subject to this Section shall file a tariff or tariffs
to implement the provisions of subsection (l) of this Section,
which shall, consistent with the provisions of subsection (l),
describe the terms and conditions under which owners or
operators of qualifying properties, units, or apartments may

10400HB1700sam002 - 634 - LRB104 08228 AAS 38463 a
participate in net metering. The Commission shall approve, or
approve with modification, the tariff within 120 days after
the effective date of this amendatory Act of the 102nd General
Assembly.
(l-10) Within 30 days after the effective date of this
amendatory Act of the 104th General Assembly, each electricity
provider shall modify its tariffs to allow net metering as set
forth in this subsection for an energy storage system or
vehicle storage system energized after the effective date of
this amendatory Act of the 104th General Assembly with a
nameplate capacity of not more than 5,000 kilowatts. If the
Commission chooses to suspend the modified tariffs, the
Commission shall issue a final order approving, or approving
with modification, the modified tariffs no later than 90 days
after the Commission initiates the docket.
An energy storage system or vehicle storage system
eligible for net metering under this subsection may be
interconnected behind the meter of a retail customer or at the
distribution system level of an electric utility as follows:
(A) if the energy storage system or vehicle storage
system is interconnected behind the meter of a retail
customer, in order to receive net metering under this
subsection, the eligible customer behind whose meter the
energy storage system is interconnected must receive
service from an electricity provider under an hourly
supply tariff, a time-of-use supply tariff, or a

10400HB1700sam002 - 635 - LRB104 08228 AAS 38463 a
time-of-use contract with an alternative retail electric
supplier; or
(B) if the energy storage system or vehicle storage
system is interconnected at the distribution system level
of an electric utility and not behind the meter of a retail
customer, the energy storage system or vehicle storage
system must receive service from an electricity provider
as a retail customer under an hourly supply tariff
authorized by Section 16-107, a supply tariff or contract
on substantially similar terms and conditions with an
alternative retail electric supplier, a time-of-use supply
tariff, or a time-of-use supply contract with an
alternative retail electric supplier.
If the energy storage system or vehicle storage system is
interconnected behind the meter of an eligible customer, the
eligible customer shall receive net metering based on hourly
or time-of-use rates in accordance with the terms of
subsection (d-5) or (f) or paragraph (2) of subsection (n) of
this Section, as applicable to the eligible customer. If the
energy storage system or vehicle storage system is
interconnected at the distribution system level of an electric
utility and not behind the meter of a retail customer, then the
energy storage system or vehicle storage system shall receive
net metering pursuant to the terms of subsection (f) of this
Section.
(m) Nothing in this Section shall affect the right of an

10400HB1700sam002 - 636 - LRB104 08228 AAS 38463 a
electricity provider to continue to provide, or the right of a
retail customer to continue to receive service pursuant to a
contract for electric service between the electricity provider
and the retail customer in accordance with the prices, terms,
and conditions provided for in that contract. Either the
electricity provider or the customer may require compliance
with the prices, terms, and conditions of the contract.
(n) On and after January 1, 2025, the net metering
services described in subsections (d), (d-5), and (e) of this
Section shall no longer be offered, except as to those
eligible renewable electrical generating facilities for which
retail customers are receiving net metering service under
these subsections at the time the net metering services under
those subsections are no longer offered; those systems shall
continue to receive net metering services described in
subsections (d), (d-5), and (e) of this Section for the
lifetime of the system, regardless of if those retail
customers change electricity providers or whether the retail
customer benefiting from the system changes. The electric
utility serving more than 200,000 customers as of January 1,
2021 is responsible for ensuring the billing credits continue
without lapse for the lifetime of systems, as required in
subsection (o). Those retail customers that begin taking net
metering service after the date that net metering services are
no longer offered under such subsections shall be subject to
the provisions set forth in the following paragraphs (1)

10400HB1700sam002 - 637 - LRB104 08228 AAS 38463 a
through (3) of this subsection (n):
(1) An electricity provider shall charge or credit for
the net electricity supplied to eligible customers or
provided by eligible customers whose electric supply
service is not provided based on hourly pricing in the
following manner:
(A) If the amount of electricity used by the
customer during the monthly billing period exceeds the
amount of electricity produced by the customer, then
the electricity provider shall charge the customer for
the net kilowatt-hour based electricity charges
reflected in the customer's electric service rate
supplied to and used by the customer as provided in
paragraph (3) of this subsection (n).
(B) If the amount of electricity produced by a
customer during the monthly billing period exceeds the
amount of electricity used by the customer during that
billing period, then the electricity provider
supplying that customer shall apply a 1:1
kilowatt-hour energy or monetary credit kilowatt-hour
supply charges to the customer's subsequent bill. The
customer shall choose between 1:1 kilowatt-hour or
monetary credit at the time of application. For the
purposes of this subsection, "kilowatt-hour supply
charges" means the kilowatt-hour equivalent values for
energy, capacity, transmission, and the purchased

10400HB1700sam002 - 638 - LRB104 08228 AAS 38463 a
energy adjustment, if applicable. Notwithstanding
anything to the contrary, customers on payment plans
or participating in budget billing programs shall have
credits applied on a monthly basis. The electricity
provider shall continue to carry over any excess
kilowatt-hour or monetary energy credits earned and
apply those credits to subsequent billing periods. For
customers with transmission or capacity charges not
charged on a kilowatt-hour basis, the electricity
provider shall prepare a reasonable approximation of
the kilowatt-hour equivalent value and provide that
value as a monetary credit. The electricity provider
shall submit these approximation methodologies to the
Commission for review, modification, and approval.
(C) (Blank).
(2) An electricity provider shall charge or credit for
the net electricity supplied to eligible customers or
provided by eligible customers whose electric supply
service is provided based on hourly or time-of-use pricing
in the following manner:
(A) If the amount of electricity used by the
customer during any hourly period exceeds the amount
of electricity produced by the customer, then the
electricity provider shall charge the customer for the
net electricity supplied to and used by the customer
as provided in paragraph (3) of this subsection (n).

10400HB1700sam002 - 639 - LRB104 08228 AAS 38463 a
(B) If the amount of electricity produced by a
customer during any hourly period exceeds the amount
of electricity used by the customer during that hourly
period, the energy provider shall calculate an energy
credit for the net kilowatt-hours produced in such
period, and shall apply that credit as a monetary
credit to the customer's subsequent bill. The value of
the energy credit shall be calculated using the same
price per kilowatt-hour as the electric service
provider would charge for kilowatt-hour energy sales
during that same hourly period and shall also include
values for capacity and transmission. For customers
with transmission or capacity charges not charged on a
kilowatt-hour basis, the electricity provider shall
prepare a reasonable approximation of the
kilowatt-hour equivalent value and provide that value
as a monetary credit. The electricity provider shall
submit these approximation methodologies to the
Commission for review, modification, and approval.
Notwithstanding anything to the contrary, customers on
payment plans or participating in budget billing
programs shall have credits applied on a monthly
basis.
(3) An electricity provider shall provide electric
service to eligible customers who utilize net metering at
non-discriminatory rates that are identical, with respect

10400HB1700sam002 - 640 - LRB104 08228 AAS 38463 a
to rate structure, retail rate components, and any monthly
charges, to the rates that the customer would be charged
if not a net metering customer. An electricity provider
shall charge the customer for the net electricity supplied
to and used by the customer according to the terms of the
contract or tariff to which the same customer would be
assigned or be eligible for if the customer was not a net
metering customer. An electricity provider shall not
charge net metering customers any fee or charge or require
additional equipment, insurance, or any other requirements
not specifically authorized by interconnection standards
authorized by the Commission, unless the fee, charge, or
other requirement would apply to other similarly situated
customers who are not net metering customers. The customer
remains responsible for the gross amount of delivery
services charges, supply-related charges that are kilowatt
based, and all taxes and fees related to such charges. The
customer also remains responsible for all taxes and fees
that would otherwise be applicable to the net amount of
electricity used by the customer. Paragraphs (1) and (2)
of this subsection (n) shall not be construed to prevent
an arms-length agreement between an electricity provider
and an eligible customer that sets forth different prices,
terms, and conditions for the provision of net metering
service, including, but not limited to, the provision of
the appropriate metering equipment for non-residential

10400HB1700sam002 - 641 - LRB104 08228 AAS 38463 a
customers. Nothing in this paragraph (3) shall be
interpreted to mandate that a utility that is only
required to provide delivery services to a given customer
must also sell electricity to such customer.
(o) Within 90 days after the effective date of this
amendatory Act of the 102nd General Assembly, each electric
utility subject to this Section shall file a tariff, which
shall, consistent with the provisions of this Section, propose
the terms and conditions under which a customer may
participate in net metering. The tariff for electric utilities
serving more than 200,000 customers as of January 1, 2021
shall also provide a streamlined and transparent bill
crediting system for net metering to be managed by the
electric utilities. The terms and conditions shall include,
but are not limited to, that an electric utility shall manage
and maintain billing of net metering credits and charges
regardless of if the eligible customer takes net metering
under an electric utility or alternative retail electric
supplier. The electric utility serving more than 200,000
customers as of January 1, 2021 shall process and approve all
net metering applications, even if an eligible customer is
served by an alternative retail electric supplier; and the
utility shall forward application approval to the appropriate
alternative retail electric supplier. Eligibility for net
metering shall remain with the owner of the utility billing
address such that, if an eligible renewable electrical

10400HB1700sam002 - 642 - LRB104 08228 AAS 38463 a
generating facility changes ownership, the net metering
eligibility transfers to the new owner. The electric utility
serving more than 200,000 customers as of January 1, 2021
shall manage net metering billing for eligible customers to
ensure full crediting occurs on electricity bills, including,
but not limited to, ensuring net metering crediting begins
upon commercial operation date, net metering billing transfers
immediately if an eligible customer switches from an electric
utility to alternative retail electric supplier or vice versa,
and net metering billing transfers between ownership of a
valid billing address. All transfers referenced in the
preceding sentence shall include transfer of all banked
credits. All electric utilities serving 200,000 or fewer
customers as of January 1, 2021 shall manage net metering
billing for eligible customers receiving power and energy
service from the electric utility to ensure full crediting
occurs on electricity bills, ensuring net metering crediting
begins upon commercial operation date, net metering billing
transfers immediately if an eligible customer switches from an
electric utility to alternative retail electric supplier or
vice versa, and net metering billing transfers between
ownership of a valid billing address. Alternative retail
electric suppliers providing power and energy service to
eligible customers located within the service territory of an
electric utility serving 200,000 or fewer customers as of
January 1, 2021 shall manage net metering billing for eligible

10400HB1700sam002 - 643 - LRB104 08228 AAS 38463 a
customers to ensure full crediting occurs on electricity
bills, including, but not limited to, ensuring net metering
crediting begins upon commercial operation date, net metering
billing transfers immediately if an eligible customer switches
from an electric utility to alternative retail electric
supplier or vice versa, and net metering billing transfers
between ownership of a valid billing address.
(Source: P.A. 104-458, eff. 6-1-26.)
(220 ILCS 5/16-107.6)
(Text of Section before amendment by P.A. 104-458)
Sec. 16-107.6. Distributed generation rebate.
(a) In this Section:
"Additive services" means the services that distributed
energy resources provide to the energy system and society that
are not (1) already included in the base rebates for
system-wide grid services; or (2) otherwise already
compensated. Additive services may reflect, but shall not be
limited to, any geographic, time-based, performance-based, and
other benefits of distributed energy resources, as well as the
present and future technological capabilities of distributed
energy resources and present and future grid needs.
"Distributed energy resource" means a wide range of
technologies that are located on the customer side of the
customer's electric meter, including, but not limited to,
distributed generation, energy storage, electric vehicles, and

10400HB1700sam002 - 644 - LRB104 08228 AAS 38463 a
demand response technologies.
"Energy storage system" means commercially available
technology that is capable of absorbing energy and storing it
for a period of time for use at a later time, including, but
not limited to, electrochemical, thermal, and
electromechanical technologies, and may be interconnected
behind the customer's meter or interconnected behind its own
meter.
"Smart inverter" means a device that converts direct
current into alternating current and meets the IEEE 1547-2018
equipment standards. Until devices that meet the IEEE
1547-2018 standard are available, devices that meet the UL
1741 SA standard are acceptable.
"Subscriber" has the meaning set forth in Section 1-10 of
the Illinois Power Agency Act.
"Subscription" has the meaning set forth in Section 1-10
of the Illinois Power Agency Act.
"System-wide grid services" means the benefits that a
distributed energy resource provides to the distribution grid
for a period of no less than 25 years. System-wide grid
services do not vary by location, time, or the performance
characteristics of the distributed energy resource.
System-wide grid services include, but are not limited to,
avoided or deferred distribution capacity costs, resilience
and reliability benefits, avoided or deferred distribution
operation and maintenance costs, distribution voltage and

10400HB1700sam002 - 645 - LRB104 08228 AAS 38463 a
power quality benefits, and line loss reductions.
"Threshold date" means December 31, 2024 or the date on
which the utility's tariff or tariffs setting the new
compensation values established under subsection (e) take
effect, whichever is later.
(b) An electric utility that serves more than 200,000
customers in the State shall file a petition with the
Commission requesting approval of the utility's tariff to
provide a rebate to the owner or operator of distributed
generation, including third-party owned systems, that meets
the following criteria:
(1) has a nameplate generating capacity no greater
than 5,000 kilowatts and is primarily used to offset a
customer's electricity load;
(2) is located on the customer's side of the billing
meter and for the customer's own use;
(3) is interconnected to electric distribution
facilities owned by the electric utility under rules
adopted by the Commission by means of one or more
inverters or smart inverters required by this Section, as
applicable.
For purposes of this Section, "distributed generation"
shall satisfy the definition of distributed renewable energy
generation device set forth in Section 1-10 of the Illinois
Power Agency Act to the extent such definition is consistent
with the requirements of this Section.

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

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products or services.
(b-5) Within 30 days after the effective date of this
amendatory Act of the 102nd General Assembly, each electric
public utility with 3,000,000 or more retail customers shall
file a tariff with the Commission that further compensates any
retail customer that installs or has installed photovoltaic
facilities paired with energy storage facilities on or
adjacent to its premises for the benefits the facilities
provide to the distribution grid. The tariff shall provide
that, in addition to the other rebates identified in this
Section, the electric utility shall rebate to such retail
customer (i) the previously incurred and future costs of
installing interconnection facilities and related
infrastructure to enable full participation in the PJM
Interconnection, LLC or its successor organization frequency
regulation market; and (ii) all wholesale demand charges
incurred after the effective date of this amendatory Act of
the 102nd General Assembly. The Commission shall approve, or
approve with modification, the tariff within 120 days after
the utility's filing.
(c) The proposed tariff authorized by subsection (b) of
this Section shall include the following participation terms
for rebates to be applied under this Section for distributed
generation that satisfies the criteria set forth in subsection
(b) of this Section:
(1) The owner or operator of distributed generation

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that services customers not eligible for net metering
under subsection (d), (d-5), or (e) of Section 16-107.5 of
this Act may apply for a rebate as provided for in this
Section. Until the threshold date, the value of the rebate
shall be $250 per kilowatt of nameplate generating
capacity, measured as nominal DC power output, of that
customer's distributed generation. To the extent the
distributed generation also has an associated energy
storage, then the energy storage system shall be
separately compensated with a base rebate of $250 per
kilowatt-hour of nameplate capacity. Any distributed
generation device that is compensated for storage in this
subsection (1) before the threshold date shall participate
in one or more programs determined through the Multi-Year
Integrated Grid Planning process that are designed to meet
peak reduction and flexibility. After the threshold date,
the value of the base rebate and additional compensation
for any additive services shall be as determined by the
Commission in the proceeding described in subsection (e)
of this Section, provided that the value of the base
rebate for system-wide grid services shall not be lower
than $250 per kilowatt of nameplate generating capacity of
distributed generation or community renewable generation
project.
(2) The owner or operator of distributed generation
that, before the threshold date, would have been eligible

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for net metering under subsection (d), (d-5), or (e) of
Section 16-107.5 of this Act and that has not previously
received a distributed generation rebate, may apply for a
rebate as provided for in this Section. Until the
threshold date, the value of the base rebate shall be $300
per kilowatt of nameplate generating capacity, measured as
nominal DC power output, of the distributed generation.
The owner or operator of distributed generation that,
before the threshold date, is eligible for net metering
under subsection (d), (d-5), or (e) of Section 16-107.5 of
this Act may apply for a base rebate for an 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. The energy storage system
shall be separately compensated at a base payment of $300
per kilowatt-hour of nameplate capacity. Any distributed
generation device that is compensated for storage in this
subsection (2) before the threshold date shall participate
in a peak time rebate program, hourly pricing program, or
time-of-use rate program offered by the applicable
electric utility. After the threshold date, the value of
the base rebate and additional compensation for any
additive services shall be as determined by the Commission
in the proceeding described in subsection (e) of this
Section, provided that, prior to December 31, 2029, the

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value of the base rebate for system-wide services shall
not be lower than $300 per kilowatt of nameplate
generating capacity of distributed generation, after which
it shall not be lower than $250 per kilowatt of nameplate
capacity. The eligibility of energy storage devices that
are interconnected behind the same retail customer meter
as the distributed generation shall not be limited to
energy storage devices interconnected after the effective
date of this amendatory Act of the 103rd General Assembly.
To the extent that an electric utility's tariffs are
inconsistent with the requirements of this paragraph (2)
as modified by this amendatory Act of the 103rd General
Assembly, such electric utility shall, within 30 days,
file modified tariffs consistent with the requirements of
this paragraph (2).
(3) Upon approval of a rebate application submitted
under this subsection (c), the retail customer shall no
longer be entitled to receive any delivery service credits
for the excess electricity generated by its facility and
shall be subject to the provisions of subsection (n) of
Section 16-107.5 of this Act unless the owner or operator
receives a rebate only for an energy storage device and
not for the distributed generation device.
(4) To be eligible for a rebate described in this
subsection (c), the owner or operator of the distributed
generation must have a smart inverter installed and in

10400HB1700sam002 - 651 - LRB104 08228 AAS 38463 a
operation on the distributed generation.
(d) The Commission shall review the proposed tariff
authorized by subsection (b) of this Section and may make
changes to the tariff that are consistent with this Section
and with the Commission's authority under Article IX of this
Act, subject to notice and hearing. Following notice and
hearing, the Commission shall issue an order approving, or
approving with modification, such tariff no later than 240
days after the utility files its tariff. Upon the effective
date of this amendatory Act of the 102nd General Assembly, an
electric utility shall file a petition with the Commission to
amend and update any existing tariffs to comply with
subsections (b) and (c).
(e) By no later than June 30, 2023, the Commission shall
open an independent, statewide investigation into the value
of, and compensation for, distributed energy resources. The
Commission shall conduct the investigation, but may arrange
for experts or consultants independent of the utilities and
selected by the Commission to assist with the investigation.
The cost of the investigation shall be shared by the utilities
filing tariffs under subsection (b) of this Section but may be
recovered as an expense through normal ratemaking procedures.
(1) The Commission shall ensure that the investigation
includes, at minimum, diverse sets of stakeholders; a
review of best practices in calculating the value of
distributed energy resource benefits; a review of the full

10400HB1700sam002 - 652 - LRB104 08228 AAS 38463 a
value of the distributed energy resources and the manner
in which each component of that value is or is not
otherwise compensated; and assessments of how the value of
distributed energy resources may evolve based on the
present and future technological capabilities of
distributed energy resources and based on present and
future grid needs.
(2) The Commission's final order concluding this
investigation shall establish an annual process and
formula for the compensation of distributed generation and
energy storage systems, and an initial set of inputs for
that formula. The Commission's final order concluding this
investigation shall establish base rebates that compensate
distributed generation, community renewable generation
projects and energy storage systems for the system-wide
grid services that they provide. Those base rebate values
shall be consistent across the state, and shall not vary
by customer, customer class, customer location, or any
other variable. With respect to rebates for distributed
generation or community renewable generation projects,
that rebate shall not be lower than $250 per kilowatt of
nameplate generating capacity of the distributed
generation or community renewable generation project. The
Commission's final order concluding this proceeding shall
also direct the utilities to update the formula, on an
annual basis, with inputs derived from their integrated

10400HB1700sam002 - 653 - LRB104 08228 AAS 38463 a
grid plans developed pursuant to Section 16-105.17. The
base rebate shall be updated annually based on the annual
updates to the formula inputs, but, with respect to
rebates for distributed generation or community renewable
generation projects, shall be no lower than $250 per
kilowatt of nameplate generating capacity of the
distributed generation or community renewable generation
project.
(3) The Commission shall also determine, as a part of
its investigation under this subsection, whether
distributed energy resources can provide any additive
services. Those additive services may include services
that are provided through utility-controlled responses to
grid conditions. If the Commission determines that
distributed energy resources can provide additive grid
services, the Commission shall determine the terms and
conditions for the operation and compensation of those
services. That compensation shall be above and beyond the
base rebate that the distributed energy generation,
community renewable generation project and energy storage
system receives. Compensation for additive services may
vary by location, time, performance characteristics,
technology types, or other variables.
(4) The Commission shall ensure that compensation for
distributed energy resources, including base rebates and
any payments for additive services, shall reflect all

10400HB1700sam002 - 654 - LRB104 08228 AAS 38463 a
reasonably known and measurable values of the distributed
generation over its full expected useful life.
Compensation for additive services shall reflect, but
shall not be limited to, any geographic, time-based,
performance-based, and other benefits of distributed
generation, as well as the present and future
technological capabilities of distributed energy resources
and present and future grid needs.
(5) The Commission shall consider the electric
utility's integrated grid plan developed pursuant to
Section 16-105.17 of this Act to help identify the value
of distributed energy resources for the purpose of
calculating the compensation described in this subsection.
(6) The Commission shall determine additional
compensation for distributed energy resources that creates
savings and value on the distribution system by being
co-located or in close proximity to electric vehicle
charging infrastructure in use by medium-duty and
heavy-duty vehicles, primarily serving environmental
justice communities, as outlined in the utility integrated
grid planning process under Section 16-105.17 of this Act.
No later than 60 days after the Commission enters its
final order under this subsection (e), each utility shall file
its updated tariff or tariffs in compliance with the order,
including new tariffs for the recovery of costs incurred under
this subsection (e) that shall provide for volumetric-based

10400HB1700sam002 - 655 - LRB104 08228 AAS 38463 a
cost recovery, and the Commission shall approve, or approve
with modification, the tariff or tariffs within 240 days after
the utility's filing.
(f) Notwithstanding any provision of this Act to the
contrary, the owner or operator of a community renewable
generation project as defined in Section 1-10 of the Illinois
Power Agency Act shall also be eligible to apply for the rebate
described in this Section. The owner or operator of the
community renewable generation project may apply for a rebate
only if the owner or operator, or previous owner or operator,
of the community renewable generation project has not already
submitted an application, and, regardless of whether the
subscriber is a residential or non-residential customer, may
be allowed the amount identified in paragraph (1) of
subsection (c) applicable on the date that the application is
submitted.
(g) The owner of the distributed generation or community
renewable generation project may apply for the rebate or
rebates approved under this Section at the time of execution
of an interconnection agreement with the distribution utility
and shall receive the value available at that time of
execution of the interconnection agreement, provided the
project reaches mechanical completion within 24 months after
execution of the interconnection agreement. If the project has
not reached mechanical completion within 24 months after
execution, the owner may reapply for the rebate or rebates

10400HB1700sam002 - 656 - LRB104 08228 AAS 38463 a
approved under this Section available at the time of
application and shall receive the value available at the time
of application. The utility shall issue the rebate no later
than 60 days after the project is energized. In the event the
application is incomplete or the utility is otherwise unable
to calculate the payment based on the information provided by
the owner, the utility shall issue the payment no later than 60
days after the application is complete or all requested
information is received.
(h) An electric utility shall recover from its retail
customers all of the costs of the rebates made under a tariff
or tariffs approved under subsection (d) of this Section,
including, but not limited to, the value of the rebates and all
costs incurred by the utility to comply with and implement
subsections (b) and (c) of this Section, but not including
costs incurred by the utility to comply with and implement
subsection (e) of this Section, consistent with the following
provisions:
(1) The utility shall defer the full amount of its
costs as a regulatory asset. The total costs deferred as a
regulatory asset shall be amortized over a 15-year period.
The unamortized balance shall be recognized as of December
31 for a given year. The utility shall also earn a return
on the total of the unamortized balance of the regulatory
assets, less any deferred taxes related to the unamortized
balance, at an annual rate equal to the utility's weighted

10400HB1700sam002 - 657 - LRB104 08228 AAS 38463 a
average cost of capital that includes, based on a year-end
capital structure, the utility's actual cost of debt for
the applicable calendar year and a cost of equity, which
shall be calculated as the sum of (i) the average for the
applicable calendar year of the monthly average yields of
30-year U.S. Treasury bonds published by the Board of
Governors of the Federal Reserve System in its weekly H.15
Statistical Release or successor publication; and (ii) 580
basis points, including a revenue conversion factor
calculated to recover or refund all additional income
taxes that may be payable or receivable as a result of that
return.
When an electric utility creates a regulatory asset
under the provisions of this paragraph (1) of subsection
(h), the costs are recovered over a period during which
customers also receive a benefit, which is in the public
interest. Accordingly, it is the intent of the General
Assembly that an electric utility that elects to create a
regulatory asset under the provisions of this paragraph
(1) shall recover all of the associated costs, including,
but not limited to, its cost of capital as set forth in
this paragraph (1). After the Commission has approved the
prudence and reasonableness of the costs that comprise the
regulatory asset, the electric utility shall be permitted
to recover all such costs, and the value and
recoverability through rates of the associated regulatory

10400HB1700sam002 - 658 - LRB104 08228 AAS 38463 a
asset shall not be limited, altered, impaired, or reduced.
To enable the financing of the incremental capital
expenditures, including regulatory assets, for electric
utilities that serve less than 3,000,000 retail customers
but more than 500,000 retail customers in the State, the
utility's actual year-end capital structure that includes
a common equity ratio, excluding goodwill, of up to and
including 50% of the total capital structure shall be
deemed reasonable and used to set rates.
(2) The utility, at its election, may recover all of
the costs as part of a filing for a general increase in
rates under Article IX of this Act, as part of an annual
filing to update a performance-based formula rate under
subsection (d) of Section 16-108.5 of this Act, or through
an automatic adjustment clause tariff, provided that
nothing in this paragraph (2) permits the double recovery
of such costs from customers. If the utility elects to
recover the costs it incurs under subsections (b) and (c)
through an automatic adjustment clause tariff, the utility
may file its proposed tariff together with the tariff it
files under subsection (b) of this Section or at a later
time. The proposed tariff shall provide for an annual
reconciliation, less any deferred taxes related to the
reconciliation, with interest at an annual rate of return
equal to the utility's weighted average cost of capital as
calculated under paragraph (1) of this subsection (h),

10400HB1700sam002 - 659 - LRB104 08228 AAS 38463 a
including a revenue conversion factor calculated to
recover or refund all additional income taxes that may be
payable or receivable as a result of that return, of the
revenue requirement reflected in rates for each calendar
year, beginning with the calendar year in which the
utility files its automatic adjustment clause tariff under
this subsection (h), with what the revenue requirement
would have been had the actual cost information for the
applicable calendar year been available at the filing
date. The Commission shall review the proposed tariff and
may make changes to the tariff that are consistent with
this Section and with the Commission's authority under
Article IX of this Act, subject to notice and hearing.
Following notice and hearing, the Commission shall issue
an order approving, or approving with modification, such
tariff no later than 240 days after the utility files its
tariff.
(i) An electric utility shall recover from its retail
customers, on a volumetric basis, all of the costs of the
rebates made under a tariff or tariffs placed into effect
under subsection (e) of this Section, including, but not
limited to, the value of the rebates and all costs incurred by
the utility to comply with and implement subsection (e) of
this Section, consistent with the following provisions:
(1) The utility may defer a portion of its costs as a
regulatory asset. The Commission shall determine the

10400HB1700sam002 - 660 - LRB104 08228 AAS 38463 a
portion that may be appropriately deferred as a regulatory
asset. Factors that the Commission shall consider in
determining the portion of costs that shall be deferred as
a regulatory asset include, but are not limited to: (i)
whether and the extent to which a cost effectively
deferred or avoided other distribution system operating
costs or capital expenditures; (ii) the extent to which a
cost provides environmental benefits; (iii) the extent to
which a cost improves system reliability or resilience;
(iv) the electric utility's distribution system plan
developed pursuant to Section 16-105.17 of this Act; (v)
the extent to which a cost advances equity principles; and
(vi) such other factors as the Commission deems
appropriate. The remainder of costs shall be deemed an
operating expense and shall be recoverable if found
prudent and reasonable by the Commission.
The total costs deferred as a regulatory asset shall
be amortized over a 15-year period. The unamortized
balance shall be recognized as of December 31 for a given
year. The utility shall also earn a return on the total of
the unamortized balance of the regulatory assets, less any
deferred taxes related to the unamortized balance, at an
annual rate equal to the utility's weighted average cost
of capital that includes, based on a year-end capital
structure, the utility's actual cost of debt for the
applicable calendar year and a cost of equity, which shall

10400HB1700sam002 - 661 - LRB104 08228 AAS 38463 a
be calculated as the sum of: (I) the average for the
applicable calendar year of the monthly average yields of
30-year U.S. Treasury bonds published by the Board of
Governors of the Federal Reserve System in its weekly H.15
Statistical Release or successor publication; and (II) 580
basis points, including a revenue conversion factor
calculated to recover or refund all additional income
taxes that may be payable or receivable as a result of that
return.
(2) The utility may recover all of the costs through
an automatic adjustment clause tariff, on a volumetric
basis. The utility may file its proposed cost-recovery
tariff together with the tariff it files under subsection
(e) of this Section or at a later time. The proposed tariff
shall provide for an annual reconciliation, less any
deferred taxes related to the reconciliation, with
interest at an annual rate of return equal to the
utility's weighted average cost of capital as calculated
under paragraph (1) of this subsection (i), including a
revenue conversion factor calculated to recover or refund
all additional income taxes that may be payable or
receivable as a result of that return, of the revenue
requirement reflected in rates for each calendar year,
beginning with the calendar year in which the utility
files its automatic adjustment clause tariff under this
subsection (i), with what the revenue requirement would

10400HB1700sam002 - 662 - LRB104 08228 AAS 38463 a
have been had the actual cost information for the
applicable calendar year been available at the filing
date. The Commission shall review the proposed tariff and
may make changes to the tariff that are consistent with
this Section and with the Commission's authority under
Article IX of this Act, subject to notice and hearing.
Following notice and hearing, the Commission shall issue
an order approving, or approving with modification, such
tariff no later than 240 days after the utility files its
tariff.
(j) No later than 90 days after the Commission enters an
order, or order on rehearing, whichever is later, approving an
electric utility's proposed tariff under this Section, the
electric utility shall provide notice of the availability of
rebates under this Section.
(Source: P.A. 102-662, eff. 9-15-21; 102-1031, eff. 5-27-22;
103-1066, eff. 2-20-25.)
(Text of Section after amendment by P.A. 104-458)
Sec. 16-107.6. Distributed generation and storage rebate.
(a) In this Section:
"Additive services" means the services that distributed
energy resources provide to the energy system and society that
are described in Section 16-107.9.
"Distributed energy resource" means a wide range of
technologies that are located on the customer side of the

10400HB1700sam002 - 663 - LRB104 08228 AAS 38463 a
customer's electric meter, including, but not limited to,
distributed generation, energy storage, electric vehicles, and
demand response technologies.
"Distributed storage" means energy storage systems that
are interconnected behind the customer's meter to the
distribution system or interconnected behind the storage
system's own meter to the distribution system and that are
permanently fixed to the distribution grid and capable of
discharging to the distribution grid. "Distributed storage"
does not include vehicle storage systems.
"Energy storage system" means commercially available
technology that is capable of absorbing energy and storing it
for a period of time for use at a later time, including, but
not limited to, electrochemical, thermal, and
electromechanical technologies, that and may be interconnected
behind the customer's meter or interconnected behind its own
meter, and that is permanently fixed to the distribution grid
and capable of discharging to the distribution grid.
"Smart inverter" means a device that converts direct
current into alternating current and meets the IEEE 1547-2018
equipment standards. Until devices that meet the IEEE
1547-2018 standard are available, devices that meet the UL
1741 SA standard are acceptable.
"Stand-alone energy storage system" means distributed
storage that is not paired with distributed generation.
"Subscriber" has the meaning set forth in Section 1-10 of

10400HB1700sam002 - 664 - LRB104 08228 AAS 38463 a
the Illinois Power Agency Act.
"Subscription" has the meaning set forth in Section 1-10
of the Illinois Power Agency Act.
"System-wide grid services" means the benefits that a
distributed energy resource provides to the distribution grid
for a period of no less than 25 years. System-wide grid
services do not vary by location, time, or the performance
characteristics of the distributed energy resource.
System-wide grid services include, but are not limited to,
avoided or deferred distribution capacity costs, resilience
and reliability benefits, avoided or deferred distribution
operation and maintenance costs, distribution voltage and
power quality benefits, and line loss reductions.
"Threshold date" means the date 2 years after the
effective date of this amendatory Act of the 104th General
Assembly or the date on which the utility's tariff or tariffs
authorized by Section 16-107.9 take effect, whichever is
later.
(b) An electric utility that serves more than 200,000
customers in the State shall file a petition with the
Commission requesting approval of the utility's tariff to
provide a rebate to the owner or operator of distributed
generation or distributed storage, including third-party owned
systems, that meets the following criteria:
(1) has a nameplate generating capacity no greater
than 5,000 kilowatts alternating current (AC) and is

10400HB1700sam002 - 665 - LRB104 08228 AAS 38463 a
primarily used to offset a customer's electricity load, or
as otherwise as defined for community renewable generation
projects in Section 1-10 of the Illinois Power Agency Act;
(2) is located on the customer's side of the billing
meter and for the customer's own use;
(3) is interconnected to electric distribution
facilities owned by the electric utility under rules
adopted by the Commission by means of one or more
inverters or smart inverters required by this Section, as
applicable.
For purposes of this Section, "distributed generation"
shall satisfy the definition of distributed renewable energy
generation device set forth in Section 1-10 of the Illinois
Power Agency Act to the extent such definition is consistent
with the requirements of this Section.
In addition, any new photovoltaic distributed generation
that is installed after June 1, 2017 (the effective date of
Public Act 99-906) must be installed by a qualified person, as
defined by subsection (i) of Section 1-56 of the Illinois
Power Agency Act.
The tariff shall include a base rebate that compensates
distributed generation and distributed storage for the
system-wide grid services associated with distributed
generation and distributed storage and an additional payment
or payments for any additive services identified by the
Commission under Section 16-107.9. The distributed generation

10400HB1700sam002 - 666 - LRB104 08228 AAS 38463 a
and distributed storage tariff shall provide that the smart
inverter or smart inverters associated with the distributed
generation and distributed storage shall provide autonomous
response to grid conditions through its default settings as
approved by the Commission. Default settings may not be
changed after the execution of the interconnection agreement
except by mutual agreement between the utility and the owner
or operator of the distributed generation and distributed
storage. Nothing in this Section shall negate or supersede
Institute of Electrical and Electronics Engineers equipment
standards or other similar standards or requirements. The
tariff shall not limit the ability of the smart inverter or
smart inverters or other distributed energy resource to
provide wholesale market products such as regulation, demand
response, or other services, or limit the ability of the owner
of the smart inverter or the other distributed energy resource
to receive compensation for providing those wholesale market
products or services.
(b-5) Within 30 days after the effective date of this
amendatory Act of the 102nd General Assembly, each electric
public utility with 3,000,000 or more retail customers shall
file a tariff with the Commission that further compensates any
retail customer that installs or has installed photovoltaic
facilities paired with energy storage facilities on or
adjacent to its premises for the benefits the facilities
provide to the distribution grid. The tariff shall provide

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that, in addition to the other rebates identified in this
Section, the electric utility shall rebate to such retail
customer (i) the previously incurred and future costs of
installing interconnection facilities and related
infrastructure to enable full participation in the PJM
Interconnection, LLC or its successor organization frequency
regulation market; and (ii) all wholesale demand charges
incurred after the effective date of this amendatory Act of
the 102nd General Assembly. The Commission shall approve, or
approve with modification, the tariff within 120 days after
the utility's filing.
To be eligible for a rebate described in this subsection
(b-5), the owner or operator of the distributed generation
shall provide proof of participation in the frequency
regulation market. Upon providing proof of participation, the
retail customer shall be entitled to a rebate equal to the cost
of the interconnection facilities paid to ComEd, regardless of
whether the retail customer would have incurred the
interconnection costs in the absence of participating in the
frequency regulation market, plus the cost of software,
telecommunications hardware, and telemetry paid to enable
communication with PJM for purposes of participating in the
frequency regulation market. A utility providing rebates
described in this subsection (b-5) shall be entitled to
recover the costs of the rebates as provided for in subsection
(h) of this Section. To the extent the electric utility's

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tariff is modified to comply with this subsection (b-5), it
shall file a revised tariff with the Commission within 120
days after the effective date of this amendatory Act of the
104th General Assembly, and the Commission shall approve, or
approve with modification, the tariff within 240 days after
the Commission initiates the docket.
(c) The proposed tariff authorized by subsection (b) of
this Section shall include the following participation terms
for rebates to be applied under this Section for distributed
generation and distributed storage that satisfies the criteria
set forth in subsection (b) of this Section:
(1) The owner or operator of distributed generation or
distributed storage that services customers not eligible
for net metering under subsection (d), (d-5), or (e) of
Section 16-107.5 of this Act may apply for a rebate as
provided for in this Section. The value of the rebate
shall be $250 per kilowatt of nameplate generating
capacity, measured as nominal DC power output, of that
customer's distributed generation. To the extent the
distributed generation also has an associated energy
storage, then until the threshold date for systems other
than community renewable generation projects paired with
an energy storage system, the energy storage system shall
be separately compensated with a rebate of $250 per
kilowatt-hour of nameplate capacity. To the extent that a
community renewable generation project is paired with an

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energy storage system or an energy storage system that is
paired with distributed generation, the energy storage
system shall be separately compensated with a rebate of
$250 per kilowatt-hour of nameplate capacity. A
stand-alone energy storage system shall be compensated
with a rebate of $250 per kilowatt-hour of nameplate
capacity. Any distributed generation device that is
compensated for storage in this paragraph subsection (1)
after the effective date of this amendatory Act of the
104th General Assembly shall participate in one or more
programs authorized by paragraph (1) of subsection (e).
Compensation for any additive services shall be as
determined by the Commission in the proceeding described
in Section 16-107.9. Except for distributed storage
projects that have obtained a signed interconnection
agreement on or before June 1, 2026, the compensation
provided for distributed storage under this paragraph (1)
shall be limited to payment for no more than 30,000
kilowatt-hours of nameplate energy capacity and no more
than 6 kilowatt-hours of nameplate energy capacity for
every one kilowatt of participating power capacity, or an
alternative nameplate energy capacity to participating
power capacity ratio determined by the Commission to
enable participation in an approved scheduled dispatch
program under paragraph (1) of subsection (e) or any
additive services or other programs as determined by the

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Commission in a proceeding described under Section
16-107.9. Notwithstanding any limitation on compensation
for distributed storage under this paragraph (1), for
distributed storage projects with more than 30,000
kilowatt-hours of nameplate energy capacity that
demonstrate that the project's interconnection application
under 83 Ill. Adm. Code 466 or 83 Ill. Adm. Code 467 was
deemed complete by the applicable utility before June 1,
2026, the compensation provided for distributed storage
under this paragraph (1) shall be limited to payment for
no more than 100,000 kilowatt-hours of nameplate energy
capacity and no more than 6 kilowatt-hours of nameplate
energy capacity for every one kilowatt of participating
power capacity for any single meter, but for no more than 2
meters per entity. Commitments to dispatch by such storage
systems in an approved scheduled dispatch program under
subsection (e) shall be mandatory. To the extent that an
electric utility's tariffs are inconsistent with the
requirements of this paragraph (1) as modified by this
amendatory Act of the 104th General Assembly, the electric
utility shall, within 60 days after the effective date of
this amendatory Act of the 104th General Assembly, file
modified tariffs consistent with the requirements of this
paragraph (1). If the Commission chooses to suspend the
modified tariffs following notice and hearing, the
Commission shall issue an order approving, or approving

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with modification, the modified tariffs no later than 90
days after the Commission initiates the docket.
(2) The owner or operator of distributed generation
that, before January 1, 2025 the threshold date, would
have been eligible for net metering under subsection (d),
(d-5), or (e) of Section 16-107.5 of this Act and that has
not previously received a distributed generation rebate,
may apply for a rebate as provided for in this Section.
Until December 31, 2029, the value of the base rebate
shall be $300 per kilowatt of nameplate generating
capacity, measured as nominal DC power output, of the
distributed generation. On or after January 1, 2030, the
value of the base rebate shall be $250 per kilowatt of
nameplate generating capacity, measured as nominal DC
power output, of the distributed generation. The owner or
operator of distributed generation that, before January 1,
2025 the threshold date, is eligible for net metering
under subsection (d), (d-5), or (e) of Section 16-107.5 of
this Act may apply for a base rebate for an 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. Distributed storage An
energy storage system, whether or not paired with
distributed generation, shall be separately compensated at
a base payment of $300 per kilowatt-hour of nameplate

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capacity until December 31, 2029 the threshold date. After
December 31, 2029 the threshold date, a stand-alone energy
storage system shall be compensated with a rebate of $250
per kilowatt-hour of nameplate capacity. Any distributed
generation device that is compensated for storage in this
subsection (2) has the option to participate in either an
hourly pricing program or time-of-use rate program and any
distributed generation device that is compensated for
storage in this subsection (2) after the effective date of
this amendatory Act of the 104th General Assembly shall
participate in a scheduled dispatch program set forth in
paragraph (1) of subsection (e) when it becomes available.
Compensation for any additive services or other programs
shall be as determined by the Commission in the proceeding
described in Section 16-107.9. Except for distributed
storage projects that have obtained a signed
interconnection agreement on or before June 1, 2026, the
compensation provided for distributed storage under this
paragraph (2) shall be limited to payment for no more than
30,000 kilowatt-hours of nameplate energy capacity and no
more than 6 kilowatt-hours of nameplate energy capacity
for every one kilowatt of participating power capacity, or
an alternative nameplate energy capacity to participating
power capacity ratio determined by the Commission to
enable participation in an approved scheduled dispatch
program under paragraph (1) of subsection (e) or any

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additive services or other programs as determined by the
Commission in a proceeding described under Section
16-107.9. Notwithstanding any limitation on compensation
for distributed storage under this paragraph (2), for
distributed storage projects with more than 30,000
kilowatt-hours of nameplate energy capacity that
demonstrate that the project's interconnection application
under 83 Ill. Adm. Code 466 or 83 Ill. Adm. Code 467 was
deemed complete by the applicable utility before June 1,
2026, the compensation provided for distributed storage
under this paragraph (2) shall be limited to payment for
no more than 100,000 kilowatt-hours of nameplate energy
capacity and no more than 6 kilowatt-hours of nameplate
energy capacity for every one kilowatt of participating
power capacity for any single meter, but for no more than 2
meters per entity. Commitments to dispatch by such storage
systems in an approved scheduled dispatch program under
subsection (e) shall be mandatory. To the extent that an
electric utility's tariffs are inconsistent with the
requirements of this paragraph (2) as modified by this
amendatory Act of the 104th General Assembly, such
electric utility shall, within 60 days, file modified
tariffs consistent with the requirements of this paragraph
(2).
(3) Upon approval of a rebate application submitted
under this subsection (c), the retail customer shall no

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longer be entitled to receive any delivery service credits
for the excess electricity generated by its facility and
shall be subject to the provisions of subsection (n) of
Section 16-107.5 of this Act unless the owner or operator
receives a rebate only for an energy storage device and
not for the distributed generation device.
(4) To be eligible for a rebate described in this
subsection (c), the owner or operator of the distributed
generation must have a smart inverter installed and in
operation on the distributed generation.
(5) The owner or operator of any distributed
generation or distributed storage system whose electric
service has not been declared competitive under Section
16-113 as of July 1, 2011 or the owner or operator of a
community renewable generation project participating in
the Adjustable Block Program as a community-driven
community solar project as defined in item (v) of
subparagraph (K) of paragraph (1) of subsection (c) of
Section 1-75 of the Illinois Power Agency Act and that has
an interconnection agreement dated after the effective
date of this amendatory Act of the 104th General Assembly
shall be eligible for an additional payment or payments to
the applicable rebate under paragraphs (1) or (2) of this
subsection (c) in an amount set by tariff and approved by
the Commission if located in an equity investment eligible
community, as defined in Section 1-10 of the Illinois

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Power Agency Act, at the time the interconnection
agreement is signed.
(d) The Commission shall review the proposed tariff
authorized by subsection (b) of this Section and may make
changes to the tariff that are consistent with this Section
and with the Commission's authority under Article IX of this
Act, subject to notice and hearing. Following notice and
hearing, the Commission shall issue an order approving, or
approving with modification, such tariff no later than 240
days after the utility files its tariff. Upon the effective
date of this amendatory Act of the 102nd General Assembly, an
electric utility shall file a petition with the Commission to
amend and update any existing tariffs to comply with
subsections (b) and (c).
(e) By no later than June 30, 2026, the Commission shall
establish a scheduled dispatch virtual power plant program in
which customers that own or operate an energy storage system
for which that receive a rebate for the distributed storage
portion was provided under paragraphs (1) and (2) of
subsection (c) are required to participate.
(1) The scheduled dispatch virtual power plant program
shall require an enrollment period of 5 years and require
each participating system to commit to dispatch each
weekday during the months of June, July, August, and
September from 4 p.m. to 6 p.m. for systems interconnected
behind the meter of a retail customer and from 4 p.m. to 7

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p.m. for systems interconnected on the distribution system
of an electric utility and not behind the meter of a retail
customer. For stand-alone storage that is not paired with
distributed generation or any electric load beyond the
electric load that is used by the energy storage system
itself, commitments to dispatch shall be voluntary. Upon
petition by the applicable electric utility or on its own
motion, the Commission may approve different dispatch
schedules provided that dispatch events do not exceed 80
days and shall not exceed 2 hours for systems
interconnected behind the meter of a retail customer or 3
hours for systems interconnected on the distribution
system of an electric utility and not behind the meter of a
retail customer.
(2) The scheduled dispatch virtual power plant program
shall be open to all customer classes with eligible
distributed storage energy resources and shall measure
performance based on combined export of paired resources
if the eligible device is inverter-based renewables paired
with storage through at least December 31, 2030 and until
the Commission approves and the utility implements a
tariff under subsection (d) of Section 16-107.9 of this
Act, at which time such customers shall be transitioned to
that tariff in a manner prescribed in the tariff. The
scheduled dispatch virtual power plant program shall be
required for all community renewable generation projects

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paired with distributed storage energy resources without
regard to the threshold date. For the purposes of this
subsection (e), "dispatch" includes any offsets of
customer usage and any exports to the utility's
distribution system.
(3) Compensation shall be set by the Commission but
shall not be less than $10 per kilowatt of average
dispatch during identified hours, paid to enrolled
customers or project owners at end of program year. For
distributed storage generation interconnected to an
electric utility's distribution system and not behind the
meter of a retail customer, dispatch to determine
compensation shall be measured at point of
interconnection. For distributed generation and storage
interconnected behind the meter of a retail customer,
dispatch to determine compensation shall be measured at
the inverter connected to the storage device.
(4) No later than June 1, 2026, each public utility
shall file an initial scheduled dispatch virtual power
plant tariff. The Commission shall approve, or approve
with modifications, the initial scheduled dispatch virtual
power plant tariff for each utility not later than June
30, 2026.
(5) The Commission, by its own motion or by petition
by an electric utility, may establish other additive
services programs in addition to the virtual power plant

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program under Section 16-107.9. Nothing in this Section is
intended to preempt or delay the implementation of other
utility programs for devices that are not a part of the
scheduled dispatch virtual power plant program that the
Commission or utility may propose or require.
(6) No later than December 31, 2028, the utilities
shall file with the Commission a report that includes
information on the following: (A) the number of
participants in the scheduled dispatch program; (B)
impacts to energy supply prices and wholesale market
activities; (C) impacts on distribution system investments
and planning; and (D) any potential pathways by which the
virtual power plan program described in Section 16-107.9
may be designed to capture wholesale market value through
participation in the wholesale market and apply that
wholesale market revenue to reduce utility distribution or
electric supply rates for customers.
(f) Notwithstanding any provision of this Act to the
contrary, the owner or operator of a community renewable
generation project as defined in Section 1-10 of the Illinois
Power Agency Act whether or not a paired energy storage system
or the owner or operator of an energy storage system that is
eligible for net metering under subsection (l-10) of Section
16-107.5 shall also be eligible to apply for the rebate
described in this Section. The owner or operator of the
community renewable generation project whether or not a paired

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energy storage system or the owner or operator of an energy
storage system that is eligible for net metering under
subsection (l-10) of Section 16-107.5 may apply for a rebate
only if the owner or operator, or previous owner or operator,
of the community renewable generation project whether or not a
paired energy storage system or the owner or operator of an
energy storage system that is eligible for net metering under
subsection (l-10) of Section 16-107.5 has not already
submitted an application, and, regardless of whether the
subscriber is a residential or non-residential customer, may
be allowed the amount identified in paragraph (1) of
subsection (c) applicable on the date that the application is
submitted.
(g) The owner of a distributed storage system, whether or
not paired with distributed generation, may apply for the
rebate or rebates approved under this Section at the time of
execution of an interconnection agreement with the
distribution utility and shall receive the value available at
that time of execution of the interconnection agreement. The
utility shall issue the rebate no later than 60 days after the
project is energized. In the event the application is
incomplete or the utility is otherwise unable to calculate the
payment based on the information provided by the owner, the
utility shall issue the payment no later than 60 days after the
application is complete or all requested information is
received.

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(h) An electric utility shall recover from its retail
customers all of the costs of the rebates made under a tariff
or tariffs approved under this Section, including, but not
limited to, the value of the rebates and all costs incurred by
the utility to comply with and implement subsections (b),
(b-5), (c), and (e) of this Section, consistent with the
following provisions:
(1) The utility shall defer the full amount of its
costs as a regulatory asset. The total costs deferred as a
regulatory asset shall be amortized over a 15-year period.
The unamortized balance shall be recognized as of December
31 for a given year. The utility shall also earn a return
on the total of the unamortized balance of the regulatory
assets, less any deferred taxes related to the unamortized
balance, at an annual rate equal to the utility's weighted
average cost of capital that includes, based on a year-end
capital structure, the utility's actual cost of debt for
the applicable calendar year and a cost of equity, which
shall be equal to the baseline cost of equity approved by
the Commission for the utility's electric distribution
rates case effective during the applicable year, whether
those rates are set pursuant to Section 9-201,
subparagraph (B) of paragraph (3) of subsection (d) of
Section 16-108.18, or any successor electric distribution
ratemaking paradigm.
When an electric utility creates a regulatory asset

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under the provisions of this paragraph (1) of subsection
(h), the costs are recovered over a period during which
customers also receive a benefit, which is in the public
interest. Accordingly, it is the intent of the General
Assembly that an electric utility that elects to create a
regulatory asset under the provisions of this paragraph
(1) shall recover all of the associated costs, including,
but not limited to, its cost of capital as set forth in
this paragraph (1). After the Commission has approved the
prudence and reasonableness of the costs that comprise the
regulatory asset, the electric utility shall be permitted
to recover all such costs, and the value and
recoverability through rates of the associated regulatory
asset shall not be limited, altered, impaired, or reduced.
To enable the financing of the incremental capital
expenditures, including regulatory assets, for electric
utilities that serve less than 3,000,000 retail customers
but more than 500,000 retail customers in the State, the
utility's actual year-end capital structure that includes
a common equity ratio, excluding goodwill, of up to and
including 50% of the total capital structure shall be
deemed reasonable and used to set rates.
(2) The utility, at its election, may recover all of
the costs as part of a filing for a general increase in
rates under Article IX of this Act, as part of an annual
filing to update a performance-based rate under Section

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16-108.18, or through an automatic adjustment clause
tariff, provided that nothing in this paragraph (2)
permits the double recovery of such costs from customers.
If the utility elects to recover the costs it incurs under
subsections (b), (b-5), (c), and (e) through an automatic
adjustment clause tariff, the utility may file its
proposed tariff together with the tariff it files under
subsection (b) of this Section or at a later time. The
proposed tariff shall provide for an annual
reconciliation, less any deferred taxes related to the
reconciliation, with interest at an annual rate of return
equal to the utility's weighted average cost of capital as
calculated under paragraph (1) of this subsection (h),
including a revenue conversion factor calculated to
recover or refund all additional income taxes that may be
payable or receivable as a result of that return, of the
revenue requirement reflected in rates for each calendar
year, beginning with the calendar year in which the
utility files its automatic adjustment clause tariff under
this subsection (h), with what the revenue requirement
would have been had the actual cost information for the
applicable calendar year been available at the filing
date. The Commission shall review the proposed tariff and
may make changes to the tariff that are consistent with
this Section and with the Commission's authority under
Article IX of this Act, subject to notice and hearing.

10400HB1700sam002 - 683 - LRB104 08228 AAS 38463 a
Following notice and hearing, the Commission shall issue
an order approving, or approving with modification, such
tariff no later than 240 days after the utility files its
tariff.
(i) (Blank).
(j) No later than 90 days after the Commission enters an
order, or order on rehearing, whichever is later, approving an
electric utility's proposed tariff under this Section, the
electric utility shall provide notice of the availability of
rebates under this Section.
(k) No later than January 1, 2030, the utilities shall
file with the Commission a report that includes:
(1) the number and geographic distribution of
participants receiving rebates pursuant to this Section;
(2) impacts to energy supply prices and wholesale
market activities;
(3) impacts on distribution system investments and
planning; and
(4) any other values deemed relevant by the
Commission.
(l) Upon petition by the applicable electric utility or on
its own motion, the Commission may adjust rebate levels for
new customers and make other appropriate changes to the rebate
program in a manner that is consistent with the State's clean
energy goals and the public interest.
(m) A vehicle storage system, as defined in Section

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16-107.5, is not eligible for a rebate under this Section.
(Source: P.A. 103-1066, eff. 2-20-25; 104-458, eff. 6-1-26.)
(220 ILCS 5/16-107.9)
(This Section may contain text from a Public Act with a
delayed effective date)
Sec. 16-107.9. Virtual power plant program.
(a) As used in this Section:
"Aggregator" means a third-party entity that participates
in the program, other than the electric utility or its
affiliate, that (i) represents and aggregates the load of
participating customers who collectively have the ability to
deploy 100 kilowatts or more of deployment of eligible devices
and (ii) is responsible for performance of the aggregation in
the program.
"Battery" means a behind-the-meter energy storage device
and associated equipment that operate together to fulfill
program requirements.
"Commission" means the Illinois Commerce Commission.
"Customer" means an active electric service account holder
of a utility.
"Direct participant" means a customer that enrolls in the
program directly with the utility, rather than participating
in the program through an aggregator.
"Distributed energy resource" has the meaning set forth in
Section 16-107.6.

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"Distributed energy resources management system" means a
platform that may be used by distribution system operators or
utilities to integrate grid resources, such as distributed
energy resources, into system operations.
"Eligible device" means a customer or third party-owned
distributed energy resource that satisfies the requirements
for participation in the program as specified in the relevant
program rider. "Eligible device" also means any device that
can be controlled to respond to pricing, provide services,
including decrease peak electricity demand or shift demand
from peak to off-peak periods, or inject power to the grid.
"Eligible device" includes, but is not limited to,
behind-the-meter energy storage systems, smart thermostats,
electric vehicle batteries, including fleets, and distributed
renewable energy devices paired with one or more energy
storage systems.
"Emergency event" means an event called by the utility
with fewer than 24 hours notice.
"Energy storage system" has the meaning set forth in
subsection (a) of Section 16-107.6.
"Enrolled customer" means a customer that participates in
the program through either an aggregator or as a direct
participant.
"Enrolled device" means an enrolled customer's eligible
device, as specified in the relevant tariff.
"Enterprise distributed energy resources management

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system" means a platform operated by the electric utility that
interfaces with a grid-edge distributed energy resources
management system to integrate distributed energy resources
into utility electric system operations.
"Grid-edge distributed energy resources management system"
means a platform owned by a party other than the electric
utility that may be used to integrate distributed energy
resources.
"Grid event" means a grid condition for which the utility
schedules or remotely dispatches enrolled devices to respond
to, as specified in the grid service opportunities for each
tariff.
"Grid service" means a capacity, energy, or ancillary
service that supports grid operations.
"Participating customer" means an aggregator or a direct
retail customer, as defined in Section 16-102, with one or
more eligible devices.
"Performance payment" means a payment made to the
participant based on the performance of an enrolled device
providing a grid service during a grid event.
"Performance payment rate" means the compensation rate
paid to participants for providing a particular grid service
during a grid event.
"Smart inverter" has the meaning set forth in subsection
(a) of Section 16-107.6.
"Upfront payment" means a one-time payment made at the

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time of enrollment.
"Virtual power plant" means an aggregation of
behind-the-meter distributed energy resources operated in
coordination to provide one or more grid services.
(b) The General Assembly finds that:
(1) virtual power plants are dynamic load management
and energy supply resources that can support grid
operations, reduce ratepayer costs, and achieve other
important public policy goals;
(2) virtual power plants can reduce demand for grid
supplied electricity during peak periods, shift
electricity consumption out of peak periods, make
renewable energy generated during off-peak periods
available for use during peak periods, supply energy to
the grid at desired times, provide frequency regulation,
voltage support, and other ancillary services, reduce
strain on the distribution system, manage localized peaks,
improve system resiliency and reliability, and provide
other grid services;
(3) virtual power plants can facilitate and optimize
the utilization of electrical generation from wind and
solar energy to help utilities increase hosting capacity
and integrate more renewable energy resources;
(4) virtual power plants can reduce costs to
ratepayers by utilizing customer-sited resources to
provide grid services, avoiding or reducing reliance on

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fossil-fuel fired peaker plants, avoiding or deferring the
need to construct new and more costly grid scale
resources, optimizing the use of existing assets, and
avoiding or deferring distribution and transmission system
upgrades and other grid investments;
(5) virtual power plants can promote equity by
reducing costs for all ratepayers, expanding access to
distributed energy resources among low-income and
moderate-income customers through improved distributed
energy resource finance ability, and providing other
important co-benefits, including reduction in emissions of
greenhouse gases and other pollutants, especially in
environmental justice and other disadvantaged communities
that host fossil fuel generation plants;
(6) the United States Department of Energy estimates
that the United States could deploy 80 to 160 gigawatts of
virtual power plants by 2030, a tripling of current
levels, to support the rapid electrification of vehicles
and homes and provide on the order of $10,000,000,000 in
ratepayer savings annually. The deployment of virtual
power plants can provide energy cost savings and other
benefits to the people of Illinois;
(7) there are significant barriers to deployment and
operation of virtual power plants, including the need for
statutory and regulatory guidance and support, greater
consistency in virtual power plant programs across

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regulatory jurisdictions, and for utility commitments to
incorporate the use of virtual power plants into system
operations and long-term resource planning;
(8) it is in the public interest to advance customer
choice and leverage the expertise of private, non-utility
entities to advance innovation and implement
cost-effective clean energy solutions; and
(9) the policy of Illinois shall be to maximize the
use of virtual power plants comprised of customer-owned
and third party-owned distributed energy resources to
deliver system services and other benefits through utility
administered virtual power plant programs in accordance
with the provisions of this amendatory Act of the 104th
General Assembly.
(c) No later than December 31, 2028, the Commission shall
approve at least one virtual power plant tariff for each
electric utility serving more than 300,000 customers in the
State as of January 1, 2023. Each utility shall file a tariff
or tariffs for approval no later than December 31, 2027 to
allow retail customers in the electric utility's service areas
to participate in a virtual power plant program proposal
consistent with the provisions of this Section. The Commission
shall provide opportunities for stakeholders to provide input
on the virtual power plant programs proposed for
implementation by each utility, which the Commission shall
take into consideration in its review of each utility's

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filing. No later than one year after the utility's filing, the
Commission shall approve or modify and approve each utility's
virtual power plant program proposal for immediate
implementation by the utility.
(d) The virtual power plant program filed under subsection
(c) shall be developed for implementation through a tariff
offering with standard terms and conditions for participation.
The virtual power plant program tariff shall allow for
customers with battery storage, non-battery storage and
electric vehicle technologies to enroll the devices in the
program through aggregators or directly with the utility. The
virtual power plant program tariff shall:
(1) provide a mechanism to incorporate existing
programs, such as smart thermostat demand-response or
electric vehicle charging programs currently offered by
the utility, under the virtual power plant program
framework;
(2) provide grid services opportunities for each
eligible technology that customers and aggregators may
provide, which shall include, at minimum, reducing the
utility's applicable capacity and transmission obligations
and capturing daily wholesale energy arbitrage
opportunities through provision of grid services;
(3) provide additional functions and grid service
opportunities that the Commission determines are
supportive of efficient planning and operation of the

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electrical grid, including:
(A) minimizing the use of fossil fuels at peak
times;
(B) local peak demand reductions;
(C) locational value;
(D) the avoidance or deferral of local
transmission or distribution upgrades or capacity
expansion;
(E) voltage support and other ancillary services;
and
(F) emergency grid services;
(4) provide operational parameters, which shall
include, at a minimum:
(A) minimum and maximum numbers of grid events for
which the utility may require dispatch from the
enrolled distributed energy resources;
(B) months of the year that grid events may occur;
(C) days of the week that grid events may occur;
(D) times of day that grid events may occur;
(E) maximum duration of grid events; and
(F) minimum day-ahead advance notification
requirement of grid events, except for emergency
events, as applicable;
(5) include provisions for aggregators to participate
in the virtual power plant program, participate in the
utility's distributed energy resource management system as

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available, automatically enroll and manage their
customers' participation, receive dispatch signals and
other communications from the utility, deliver performance
measurement and verification data to the utility, and
receive virtual power plant program payments directly from
the utility;
(6) include provisions that provide a standardized
process for any eligible aggregator to enroll in the
program and authorize the eligible aggregators to manage
individual customer device participation without
additional authorizations from the utility;
(7) include provisions that allow a participating
customer with multiple eligible devices to enroll the
technologies either directly without an aggregator or
through one or more aggregators in applicable programs
under the tariff approved under this Section, provided
that no particular device is accounted for more than once;
(8) include provisions for direct participant
customers to participate with the utility's distributed
energy resource management system as available, receive
dispatch signals and other communications from the
utility, deliver performance measurement and verification
data to the utility, and receive virtual power plant
program payments directly from the utility. Any provisions
implementing this subpart that necessitate the
installation of equipment to enable direct participation

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via the utility shall apply to customers who elect to
participate as a direct participant and shall not be
required of customers who participate via an aggregator or
to customers who do not participate in the virtual power
plant program;
(9) provide for measurement and verification of
battery non-battery, and electric vehicle technologies
performance directly at the device without the requirement
for the installation of an additional meter;
(10) include upfront payment or performance payment
compensation mechanisms for the peak reduction service, as
well as for non-battery and electric vehicle technologies
as the Commission deems appropriate. The performance
payment shall be based on the average capacity provided
during grid events. The Commission shall approve
additional compensation mechanisms as it determines
appropriate for other grid services provided under the
battery, non-battery and electric vehicle riders. The
virtual power plant program shall not assess penalties for
non-performance; provided, however, that the Commission
may approve reasonable mechanisms to disenroll customers
for continued non-performance;
(11) enable low-to-moderate income customers,
community-driven community solar projects, and customers
whose electric service has not been declared competitive
pursuant to Section 16-113 as of July 1, 2011 located in

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equity investment eligible investment communities to
receive a higher upfront enrollment payment. The
Commission shall coordinate with State energy officials
and departments to make funding from federal programs and
such other sources as may be available for use in
providing higher upfront payments to customers classes as
may be approved by the Commission in accordance with this
subsection;
(12) provide that the performance payment rate
applicable at the time of enrollment shall be for 5 years,
after which time the participant may reenroll at the then
applicable performance payment rate for an additional
5-year term;
(13) provide for a transition of customers from the
scheduled dispatch program described in Section 16-107.6
to the virtual power plant program; and
(14) allow enrolled customers to participate in other
applicable interconnection tariffs and grid service
programs outside the virtual power plant program, so long
as it does not result in double-counting of benefits for
the same grid services.
(e) The Commission may adopt other reasonable requirements
for participation consistent with this subsection, provided
that collateral from an aggregator shall not be required for
participation.
(f) The utility may contract with a third party-owned

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distributed energy resource management system provider to
assist with program implementation; however, implementation
shall not be delayed due to the lack of utility-owned
distributed energy resource management system capabilities or
third party-owned distributed energy resource management
system capabilities.
(g) The utility shall not send or receive dispatch signals
directly to or from any participating customer represented by
an aggregator for an event under the virtual power plant
program described in this Section.
(h) Participating aggregators shall have capabilities to
receive event signals from utilities or utility-contracted
distributed energy resources management system providers. To
facilitate the adoption of and participation in the virtual
power plant program, the utility shall allow and enable
participating customers to expeditiously share their customer
information with aggregators in order to serve any contracted
customers and comply with any reporting requirements.
(i) Utilities shall recover reasonably and prudently
incurred costs to facilitate the virtual power plant program
approved under subsection (c), including, but not limited to,
distributed energy resource management systems provider and
other service contract costs, operations and maintenance
expenses, information technology costs, and other costs,
expenses, and investments that the Commission finds necessary
and prudent for the development and implementation of the

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program. The utility shall recover the cost of virtual power
plant program upfront payments and performance payments and
such other payments made to participants through the tariff
filed pursuant to subsection (h) of Section 16-107.6.
(j) No later than January 31 of each year, each utility
shall file an annual report that includes, but is not limited
to:
(1) the total capacity enrolled in each program rider
developed in accordance with the requirements of Section,
broken down by technology type, customer class, and
aggregator and direct participant status for each grid
service opportunity offered in the prior calendar year;
(2) recommendations to increase participation in the
virtual power plant program; and
(3) any other information that the Commission may
require.
(k) Each utility shall amend existing tariffs and
procedures that limit the ability of customers to participate
in providing grid services under the program, such as
limitations on charging energy storage devices with grid
energy or exporting energy to the grid from battery discharge.
(l) The tariffs approved by the Commission shall not
reflect any additional charges, fees, or insurance
requirements imposed on those owning or operating
demand-response technologies beyond those imposed on similarly
situated customers that do not own or operate demand-response

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technologies.
(m) As a condition of participating in the programs
described in this Section, prior to enrollment of a customer
by an aggregator, the aggregator shall disclose the following:
(1) the payments, expressed as an amount or a formula,
to be provided to the customer;
(2) between the aggregator and customer, who is
responsible for paying penalties or fees; and
(3) between the aggregator and customer, who is
responsible for posting collateral, if required.
Any tariff authorized by this Section shall incorporate
the requirements under this subsection and shall require the
electric utility to establish a complaint and Commission
notification process and, on order of the Commission, suspend
any aggregator repeatedly or egregiously violating such
requirements.
(Source: P.A. 104-458, eff. 6-1-26.)
(220 ILCS 5/16-202)
(This Section may contain text from a Public Act with a
delayed effective date)
Sec. 16-202. Integrated resource plan review and approval.
(a) The Commission shall enter its order approving or
approving with modifications an integrated resource plan
within 180 days after the agencies filing the plan and any
companion reports or other information. The Commission may

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extend the period of review of the plan for no more than an
additional 180 days.
(b) The Commission may approve a plan or a modified plan
and authorize its implementation only if, after notice and
hearing, including the conduct of discovery and taking of
evidence, it finds that the plan:
(1) addresses any resource adequacy challenges in the
5 years immediately following approval of the plan, while
also taking into account the 10 years following the plan;
(2) prepares the State to best address issues of
resource adequacy at the least amount of CO2e and
copollutant emissions;
(3) considers the emissions' impacts on environmental
justice communities while taking into account all
applicable labor and equity standards;
(4) supports the provisioning of adequate, reliable,
affordable, efficient, and environmentally sustainable
electric service at the lowest total cost over time; and
(5) utilizes the expansion of renewable energy, energy
storage, virtual power plants and distributed energy
storage, energy efficiency, demand response, time-of-use
rates or other mechanisms designed to manage peak load,
transmission development, carbon mitigation credits or any
other clean energy strategies to the maximum extent
practicable to resolve any identified resource adequacy
shortfall or reliability violation in a cost-effective,

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affordable, timely, and clean manner.
(c) The Commission may, as a part of its decision to
approve a plan or modified plan and to the extent consistent
with the uniform allocation of costs required under subsection
(k) of Section 16-108, order changes to existing plans or
programs, direct specific actions within existing plans or
programs, including the authorization to support the expansion
of an existing plan or program, including, but not limited to:
(1) any of the following plans or programs designed to
increase the amount of generation and capacity available:
(i) the Long-Term Renewable Resources Procurement
Plan, including programs and procurements authorized
through that Plan, and to increase the limitations
placed on the procurement of renewable energy
resources established pursuant to subparagraph (E) of
paragraph (1) of subsection (c) of Section 1-75 of the
Illinois Power Agency Act in order to increase,
direct, or adjust procurements of renewable energy
resources to support new renewable energy projects;
(ii) the Energy Storage Resources Procurement
Plan, including programs and procurements authorized
through that Plan, and to increase the procurement of
energy storage established pursuant to subsection
(d-20) of Section 1-75 of the Illinois Power Agency
Act in order to increase or adjust procurements for
new energy storage;

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(iii) the carbon mitigation credit procurement
plans established pursuant to subsection (d-10) of
Section 1-75 of the Illinois Power Agency Act in order
to preserve existing carbon-free energy resources,
including extending or expanding carbon mitigation
credit contract awards in accordance with a new
schedule of baseline costs;
(iv) the Illinois Power Agency's annual
electricity procurement plans established pursuant to
paragraph (2) of subsection (d) of Section 16-111.5,
including modification of the products to be procured
and allowing for costs associated with the purchase of
new or additional products to be socialized across all
retail customers or all load-serving entities, as
applicable; and
(v) any plan to reduce or delay CO2e and
copollutant emissions reductions requirements that is
submitted by the Illinois Power Agency and
Environmental Protection Agency and approved by the
Commission under subsection (o) of Section 9.15 of the
Environmental Protection Act; and
(vi) (v) any additional plans or programs designed
to procure appropriate sources of new clean energy and
capacity resources, including any associated clean
attribute credits; and
(2) any of the following designed to manage energy

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demand, including, but not limited to:
(i) extending or expanding the energy efficiency
programs implemented by electric utilities and the
limitation on the amount of energy efficiency and
demand-response measures implemented pursuant to
Section 8-103B in order to gain increased load
reductions; and
(ii) the Multi-Year Integrated Grid Plans
implemented by electric utilities pursuant to Section
16-105.17 in order to extend or expand programs
related to peak load management and reduction,
including, but not limited to, virtual power plants,
front of the meter distributed storage, demand
response, and time-of-use rates.
(d) If all of the changes made to the plans or programs
pursuant to this Section would reasonably be insufficient to
balance supply and demand and avoid a resource adequacy
shortfall, then the Commission may delay, in whole or in part,
the CO2e and copollutant emissions reductions requirements
found in Section 9.15 of the Environmental Protection Act but
only to the minimum extent and duration necessary to address
the resource adequacy shortfall needs of the State. If the
Commission finds that reducing or delaying the emissions
reductions requirements is necessary, despite any or all of
the changes made pursuant to this Section, then it shall also
include in its final order recommendations to the General

10400HB1700sam002 - 702 - LRB104 08228 AAS 38463 a
Assembly on what additional policies may be adopted that could
avoid future modifications to the emissions reductions.
(e) Unless otherwise specified by the Commission, the
order approving the plan or modified plan shall become
effective January 1 of the calendar year immediately following
the issuance of the order. The agencies, electric utilities,
and any other impacted entities shall comply with any of the
Commission's orders, and when required seek approval from the
Commission and make any required modifications to their plans,
programs, or related initiatives in a manner consistent with
the process and timing for those changes as outlined in the
approved plans or, if none is specified, as soon as
practicable. If the integrated resource plan approved by the
Commission contains recommendations that are outside the
Commission's authority, the Commission shall communicate any
such recommendations to the Governor and the General Assembly.
(f) Given the critical and rapid actions required under
this Section, the Commission may procure the services of any
facilitator, expert, or consultant, including the procurement
monitor retained by the Commission pursuant to paragraph (2)
of subsection (c) of Section 16-111.5. Such procurement is
exempt from the requirements of the Illinois Procurement Code,
pursuant to Section 20-10 of that Code.
(g) Costs that are prudently and reasonably incurred by
electric utilities to comply with the requirements of this
Section shall be recovered and shall be excluded from the

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calculation performed under paragraph (6) of subsection (f) of
Section 16-108.18. Nothing in the Commission's order directing
changes to a prior approved plan as enumerated in this Section
shall be the sole basis for a finding of imprudence or
unreasonableness or the lack of use or usefulness of any
investment or expenditure.
(h) If the Commission's final order under this Section
includes the approval of rate increases through the expansion
of existing plans or programs, the creation of new plans or
programs, or the increase of limitations placed on
procurements as described under paragraphs (1) and (2) of
subsection (c), the Commission shall submit notice to the
General Assembly of the increases included in the final order,
including the estimated monthly cost impact on customers and
the expected costs savings or benefits of such actions. After
receipt of a notice, any member of the General Assembly may
introduce in the General Assembly a joint resolution stating
that the General Assembly desires to suspend the rate
increases, or suspend a portion of the rate increases,
identified in the final order and specifying the rationale for
the General Assembly's determination.
(1) If the General Assembly passes a joint resolution
under this subsection (h) that takes effect prior to the
effective date of the Commission's final order, the
General Assembly shall send notice to the Commission of
the resolution, and the Commission shall suspend its final

10400HB1700sam002 - 704 - LRB104 08228 AAS 38463 a
order. Within 30 days of receipt of the General Assembly's
notice, the Commission shall reopen the docket approving
the plan or modified plan in order to take into account the
General Assembly's reduction or elimination of the rate
increases. The Commission shall approve the modified plan
within 120 days of reopening the docket, including the
conduct of discovery and the taking of evidence, and send
notice to the General Assembly of its modified plan. The
General Assembly may rescind its desire to suspend the
rate increases, or suspend a portion of the rate
increases, by adoption of a subsequent joint resolution by
each chamber of the General Assembly within 30 days of
receipt of the Commission's notice that would put into
effect the Commission's original final order.
(2) If the General Assembly fails to pass a joint
resolution under this subsection (h) prior to the
effective date of the Commission's final order, the
associated rate increases shall go into effect pursuant to
the schedule specified in the Commission's final order
approving the plan or modified plan.
(i) The Commission may adopt rules to implement the
requirements of this Section.
(Source: P.A. 104-458, eff. 6-1-26.)
(220 ILCS 5/20-140)
(This Section may contain text from a Public Act with a

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delayed effective date)
Sec. 20-140. Interconnection Working Group.
(a) The Commission shall establish an Interconnection
Working Group. The Working Group shall include representatives
from electric utilities, developers of renewable electric
generating facilities, representatives of new large loads
seeking grid interconnection, other industries that regularly
apply for interconnection with the electric utilities as
appropriate, representatives of distributed generation
customers, the Commission staff, and other stakeholders with a
substantial interest in the topics addressed by the
Interconnection Working Group.
(b) The Interconnection Working Group shall address at
least the following issues in relation to new generation and
new large loads:
(1) the cost of and the best available technology for
interconnection and metering, including the
standardization and publication of standard costs;
(2) transparency, accuracy, and use of the
distribution interconnection queue and hosting capacity
maps;
(3) distribution system upgrade cost avoidance through
use of advanced inverter functions, energy storage, and
load management;
(4) predictability of the queue management process and
enforcement of timelines;

10400HB1700sam002 - 706 - LRB104 08228 AAS 38463 a
(5) benefits and challenges associated with group
studies and cost sharing;
(6) minimum requirements for application to the
interconnection process and throughout the interconnection
process to avoid queue clogging behavior;
(7) the process and customer service for
interconnecting customers adopting distributed energy
resources, including energy storage;
(8) options for metering distributed energy resources,
including energy storage;
(9) interconnection of new technologies, including
smart inverters and energy storage;
(10) collection, examination, and sharing of data on
Level 1 interconnection costs, including cost and type of
upgrades required for interconnection, and the use of this
data to inform the final standardized cost of Level 1
interconnection;
(11) determination of a single standardized cost for
Level 1 interconnections, which shall not exceed $200; and
(12) such other technical, policy, and tariff issues
related to and affecting interconnection performance and
customer service as determined by the Interconnection
Working Group.
(c) The Commission may create subcommittees of the
Interconnection Working Group to focus on specific issues of
importance, as appropriate.

10400HB1700sam002 - 707 - LRB104 08228 AAS 38463 a
(d) The Interconnection Working Group shall report to the
Commission on recommended improvements to interconnection
rules, tariffs, and policies as determined by the
Interconnection Working Group at least every year. A report
shall include consensus recommendations of the Interconnection
Working Group and, if applicable, additional recommendations
for which consensus was not reached. Non-consensus shall not
be a basis for excluding recommendations that are majority or
minority recommendations. The Commission shall use the report
from the Interconnection Working Group to determine whether
processes should be commenced to formally codify or implement
the recommendations. The Interconnection Working Group shall
provide the reports under this subsection (d) to the
Commission on at least the following topics in the order
listed below within a reasonable time, but no later than 12
months, after the effective date of this amendatory Act of the
104th General Assembly: (A) a mechanism for good cause
extensions to construction timelines as long as the
interconnection customer reasonably demonstrates progress; (B)
a mechanism for all electric utilities to accept cash, letters
of credit, or bonds for any deposits required under the
interconnection agreement; (C) cost sharing for distribution
system upgrades and interconnection facilities for multiple
interconnection customers attempting to interconnect on the
same feeder or substation; (D) requirements that utilities
initiate the interconnection study process interconnection

10400HB1700sam002 - 708 - LRB104 08228 AAS 38463 a
studies process without delay based on queue position or
status of applications ahead in the queue, and associated
requirements for disclosure of contingent upgrades; (E)
provisions allowing for queue reservation for the
interconnection of projects installed on public school land to
accommodate timing constraints of school board approval and
budgeting; and (F) if feasible within the time allotted for
the initial report, parameters for utility interconnection
studies of energy storage systems not paired with distributed
generation that are based on the proposed operational profile
of the energy storage systems.
(d-5) Within 12 months after the report directed by
subsection (d) has been submitted, the Working Group shall
report to the Commission on the following: (A) mandatory
disclosures on the hosting capacity map and studies for
contingent upgrades including timelines for notice of
responsibility and payment; (B) a framework for concurrent
study on multiple feeders for a distributed energy resource;
and (C) if not provided in the initial report required under
subsection (d), parameters for utility interconnection studies
of energy storage systems not paired with distributed
generation that are based on the proposed operational profile
of the energy storage systems.
(d-10) Within 12 months after the report directed by
subsection (d-5) has been submitted, the Working Group shall
report to the Commission on the following: (A) dynamic hosting

10400HB1700sam002 - 709 - LRB104 08228 AAS 38463 a
capacity maps; (B) standards for public queue and hosting
capacity map information regarding individual projects in
queue, including (i) distributed generation nameplate
capacity, (ii) paired or stand-alone energy storage system
nameplate capacity, (iii) detailed estimated upgrade costs,
and (iv) systems that have completed upgrades and withdrawn
projects; and (C) timelines for refund of deposits if the
interconnection agreement is terminated. Within the same time
period, utilities shall publish all final interconnection
agreements, facilities studies, and system impact studies.
(d-15) Within 12 months after the report directed by
subsection (d-10) has been submitted, the Working Group shall
report to the Commission on the following: (A) level of detail
of costs in system impact and facilities studies and level 2
studies; and (B) a cap on charges to the interconnection
customer based on a percentage of the non-binding cost
estimate in the facilities study, system impact study, or
level 2 study.
(e) In collaboration with the General Counsel of the
Commission, the Office of Retail Market Development shall
develop policies and procedures to facilitate employees of the
Office in leading the Interconnection Working Group without
interference with docketed proceedings. The policies and
procedures developed under this subsection (e) shall be
designed to allow the Interconnection Working Group to work
without interruption.

10400HB1700sam002 - 710 - LRB104 08228 AAS 38463 a
(Source: P.A. 104-458, eff. 6-1-26.)
(220 ILCS 5/23-115)
(This Section may contain text from a Public Act with a
delayed effective date)
Sec. 23-115. Resolution of disputes between facility
owners and units of local government related to the siting of
qualified energy facilities.
(a) The expedited procedures in this Section shall be used
to enforce the provisions of the applicable State siting law.
(b) No petition may be filed under this Section until the
facility owner that intends to file the petition has first
notified the respondent of the alleged violation of the
applicable State siting law and offered the respondent 7 days
to correct or take substantial steps to begin and diligently
pursue curing the alleged violation. Provision of notice and
the opportunity to correct the situation creates a rebuttable
presumption of knowledge under this Section. After the filing
of a petition under this Section, the parties may agree to
follow the mediation process under Section 10-101.1 of this
Act. The time periods specified in subdivision (c)(7) of this
Section shall be tolled during the time spent in mediation
under Section 10-101.1.
(c) A facility owner may file a petition with the
Commission alleging a violation of the applicable State siting
law in accordance with this subsection. The following

10400HB1700sam002 - 711 - LRB104 08228 AAS 38463 a
procedures shall govern the dispute resolution process:
(1) The petition shall be filed with the Chief Clerk
of the Commission and shall be served in hand upon the
respondent, the executive director, and the general
counsel of the Commission at the time of the filing.
(2) A petition filed under this subsection shall
include a statement that the requirements of subsection
(b) have been fulfilled and that the respondent did not
correct the situation as requested.
(3) Reasonable discovery specific to the issue of the
petition may commence upon filing of the petition.
(4) An answer and any other responsive pleading to the
petition shall be filed with the Commission and served at
the same time upon the complainant, the executive
director, and the general counsel of the Commission within
7 days after the date on which the petition is filed.
(5) If the answer or responsive pleading raises the
issue that the petition violates subsection (f) of this
Section, the complainant may file a reply to such
allegation within 3 days after actual service of such
answer or responsive pleading. Within 4 days after the
time for filing a reply has expired, the administrative
law judge shall either issue a written decision dismissing
the petition as frivolous in violation of subsection (f)
of this Section including the reasons for such disposition
or shall issue an order directing that the petition shall

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proceed.
(6) A pre-hearing conference shall be held within 14
days after the date on which the petition is filed.
(7) The hearing shall commence within 45 days of the
date on which the petition is filed and shall be conducted
by an administrative law judge. Parties and the Commission
staff shall be entitled to present evidence and legal
argument in oral or written form as deemed appropriate by
the administrative law judge. The administrative law judge
shall issue a proposed order within 90 days after the date
on which the petition is filed. The proposed order shall
include reasons for the disposition of the petition and,
if a violation of the applicable State siting law is
found, directions and a deadline for correction of the
violation.
(8) Any party may file a petition requesting the
Commission to review the proposed order of the
administrative law judge or arbitrator within 5 days after
the proposed order is issued and file exceptions to the
proposed order. Any party may file a response to a
petition for review within 3 business days after actual
service of the petition. After the time for filing of the
petition for review, but no later than 60 days after the
proposed order of the administrative law judge, the
Commission shall decide to adopt the proposed order of the
administrative law judge or shall issue its own final

10400HB1700sam002 - 713 - LRB104 08228 AAS 38463 a
order.
(d) In resolving disputes filed under this Section, the
administrative law judge and the Commission shall make
determinations based on the requirements and intent of the
applicable State siting law.
(e) In resolving disputes under this Section, the
Commission shall have authority to issue a siting certificate
for a qualified energy facility if the Commission determines
that the qualified energy facility is in compliance with the
applicable State siting law for a qualified energy facility
and that the respondent:
(1) has the respondent denied the qualified energy
facility a siting certificate; or and
(2) has failed or declined to issue the qualified
energy facility a siting certificate in a timely manner.
the qualified energy facility is in compliance with the
applicable State siting laws for a qualified energy
facility.
For the purposes of this Section, a commercial wind energy
facility and commercial solar energy facility shall be in
compliance with Section 5-12020 of the Counties Code and an
energy storage system shall be in compliance with Section
5-12024 of the Counties Code. If the Commission determines
that there is substantial harm to the facility owner, the
Commission may, notwithstanding any other provision of this
Act, seek temporary, preliminary, or permanent injunctive

10400HB1700sam002 - 714 - LRB104 08228 AAS 38463 a
relief from a court of competent jurisdiction either before or
after the hearing.
(f) A party shall not bring or defend a proceeding brought
under this Section or assert or controvert an issue in a
proceeding brought under this Section, unless there is a
non-frivolous basis for doing so. By presenting a pleading,
written motion, or other paper in petition or defense of the
actions or inaction of a party under this Section, a party is
certifying to the Commission that to the best of that party's
knowledge, information, and belief, formed after a reasonable
inquiry of the subject matter of the petition or defense, that
the petition or defense is well grounded in law and fact, and
under the circumstances:
(1) it is not being presented to harass the other
party, cause unnecessary delay, or create needless
increases in the cost of litigation; and
(2) the allegations and other factual contentions have
evidentiary support or, if specifically so identified, are
likely to have evidentiary support after reasonable
opportunity for further investigation or discovery as
defined herein.
(g) If, after notice and a reasonable opportunity to
respond, the Commission determines that subsection (f) has
been violated, the Commission shall impose appropriate
sanctions upon the party or parties that have violated
subsection (f) (i) or are responsible for the violation.

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(h) An appeal of a Commission order made pursuant to this
Section shall not effectuate a stay of the order unless a court
of competent jurisdiction specifically finds that the party
seeking the stay will likely succeed on the merits, that the
party will suffer irreparable harm without the stay, and that
the stay is in the public interest.
(i) The Commission shall assess the parties under this
subsection for all of the Commission's costs of investigation
and conduct of the proceedings brought under this Section
including, but not limited to, the prorated salaries of staff,
attorneys, administrative law judges, and support personnel
and including any travel and per diem, directly attributable
to the petition brought pursuant to this Section, but
excluding those costs provided for in subsection (g), dividing
the costs according to the resolution of the petition brought
under this Section. All assessments made under this subsection
shall be paid into the Public Utility Fund within 60 days after
receiving notice of the assessments from the Commission.
Interest at the statutory rate shall accrue after the
expiration of the 60-day period. The Commission is authorized
to apply to a court of competent jurisdiction for an order
requiring payment.
(Source: P.A. 104-458, eff. 6-1-26.)
Section 30. The Utility Data Access Act is amended by
changing Sections 5-10 and 5-15 as follows:

10400HB1700sam002 - 716 - LRB104 08228 AAS 38463 a
(220 ILCS 33/5-10)
(This Section may contain text from a Public Act with a
delayed effective date)
Sec. 5-10. Definitions. As used in this Act:
"Account holder" or "customer" means the person or entity
authorized to access or modify utility account details.
"Aggregated usage data" means an aggregation of covered
usage data, where all data associated with a qualified
building or qualified property, including, but not limited to,
data from tenant meters and from owner meters, are combined
into one collective data point per utility data type, per time
period, and where any unique identifiers or other personal
information are removed or dissociated from individual meter
data.
"Aggregation threshold" means 3 or more unique
nonresidential qualified accounts or any combination of 5 or
more residential and nonresidential unique qualified accounts
of a property or building during the period for which data is
requested.
"Benchmarking tool" means the ENERGY STAR Portfolio
Manager web-based tool or any prudent and cost-effective
alternative system or tool approved by the Commission should
ENERGY STAR Portfolio Manager become inoperative or no longer
useful to achieving the policy goals of the State of Illinois
that (i) enables the periodic entry of a building's energy use

10400HB1700sam002 - 717 - LRB104 08228 AAS 38463 a
data and other descriptive information about a building and
(ii) rates a building's energy efficiency against that of
comparable buildings nationwide.
"Commission" means the Illinois Commerce Commission.
"Covered usage data" means electric or gas data collected
from one or more utility meters that reflects the quantity and
period of utility usage in the building, property, or portion
thereof.
"Data recipient" means:
(1) an owner of the property or building;
(2) an owner of a portion of a property with regard to
covered usage data only for the utility consumption the
owner or the owner's tenants, if any, pay for and consume
in the owned portion;
(3) a tenant with regard to covered usage data only
for the utility consumption the tenant or the tenant's
subtenants, if any, pay for and consume in the space
leased by the tenant;
(4) the board, in the case of a condominium or
cooperative ownership of the property or building; or
(5) an agent authorized to receive the covered usage
data by anyone in paragraphs (1) through (4).
"Property" means:
(1) a single tax parcel;
(2) 2 or more tax parcels held in the cooperative or
condominium form of ownership and governed by a single

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board of managers; or
(3) 2 or more colocated tax parcels owned or
controlled by the same entity.
"Qualified account" means a utility account that serves
some or all of a building or property for which covered usage
data is requested and that, as affirmed by the data recipient,
was not controlled by the data recipient or its subsidiary
during the time period for which covered usage data is
requested.
"Qualified building" means a building that meets the
aggregation threshold.
"Qualified data recipient" means a data recipient with
respect to a qualified property or qualified building.
"Qualified property" means a property that meets the
aggregation threshold.
"Utility" means an entity that is an electric or gas
utility with over 100,000 500,000 customers in this State and
that is a public utility, as defined in Section 3-105 of the
Public Utilities Act.
"Utility data type" means electric or gas.
(Source: P.A. 104-458, eff. 6-1-26.)
(220 ILCS 33/5-15)
(This Section may contain text from a Public Act with a
delayed effective date)
Sec. 5-15. Utility data access.

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(a) Within 90 days after the effective date of this Act,
the Commission shall open a proceeding to establish by rule,
consistent with the Illinois Administrative Procedure Act and
the requirements of subsection (c), procedures to implement
the requirements of this Section. The Commission shall
consider industry best practices along with Illinois law,
rules, and Commission orders in developing the implementing
rules. The governing authority of a public utility district,
municipally owned utility, or cooperative utility may adopt a
rule adopted by the Commission.
(b) No later than 2 years after the effective date of this
Act, the Commission shall adopt procedures through the
rulemaking proceeding identified in subsection (a) whereby:
(1) a utility shall retain usage data in the
possession of the utility on the effective date of this
Act or that is subsequently generated by the utility, for
a period 5 years or however long the utility retains usage
data in its active billing system, whichever is longer;
(2) a utility shall honor an account holder's
authorized request to transmit the account holder's
covered usage data held by the utility to any entity
designated by the account holder;
(3) a qualified data recipient with respect to a
qualified building or qualified property may request that
a utility provide aggregated usage data for the qualified
building or qualified property. Aggregated usage data

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shall include identifiers of all meters associated with
the aggregate data and any other information needed for
data quality assurance;
(4) a utility shall establish a tool or process, or
use an existing tool or process, to enable qualified data
recipients to request data under this subsection. The tool
or process shall meet specifications established by the
Commission;
(5) the account holder request process and utility
delivery of requested data shall be convenient, secure,
and at the Commission's direction requests to the utility
may be submitted exclusively through an online portal; and
(6) a utility shall provide updates or corrections to
any previously provided usage information on the schedule
established in paragraph (5) of subsection (d). Data
recipients may request and receive timely revisions
correcting any previously provided usage information. A
utility shall also provide usage information on the
schedule established in paragraph (5) of subsection (d).
Notwithstanding any other law, aggregated usage data from
multiple customer accounts shall not be deemed customer
utility usage information, personally identifiable
information, or confidential information and shall not be
subject to protections for customer utility usage information,
personally identifiable information, or confidential
information.

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(c) Any covered usage data that a utility provides to a
data recipient under this Section must meet the following
requirements:
(1) The covered usage data must be available to be
requested online. A utility's validation of the
requester's identity shall be consistent with, and no more
onerous than, the utility's then-current practices.
(2) The covered usage data must be provided to the
data recipient in a timeframe, frequency, and format and
be delivered by a method as may be determined by the
Commission.
(d) Any covered usage data that a utility provides to a
data recipient under this Section must:
(1) be provided to the data recipient within 30 days
after receiving the data recipient's valid request if the
request is received after the effective date of the
rulemaking identified in subsection (a) of this Section;
(2) for any initial upload of data to a data recipient
and subject to subsection (j) of this Section, a data
recipient must include all the data for the time period
required in paragraph (1) of subsection (b), regardless of
whether the data recipient had a business relationship
with the building or property during that period;
(3) include all necessary data and available usage
data points for data recipients to comply with reporting
requirements to which they are subject, including any such

10400HB1700sam002 - 722 - LRB104 08228 AAS 38463 a
usage data that the utility possesses;
(4) be directly uploaded to the benchmarking tool
account, or delivered in another format approved by the
Commission, depending on utility size under subsection
(e);
(5) be provided to the data recipient according to a
schedule set by the Commission, but no less than monthly;
(6) be provided until the data recipient revokes the
request for usage data or is no longer a data recipient or
is no longer a qualified data recipient with respect to
aggregated usage data;
(7) be accompanied by a list of all meters associated
with the covered usage data, including, but not limited
to, aggregated usage data, and shall be accompanied by any
other information the Commission deems necessary including
for data quality assurance; and
(8) be provided at no cost to the data recipient.
(e) The Commission shall direct that covered usage data
shall be delivered to the data recipient in a standard format
consistent with the benchmarking tool at the data recipient's
request. The Commission shall direct electric utilities that
serve at least 100,000 500,000 customers in the State to
provide requested data by direct upload to the benchmarking
tool and associate the data with the data recipient's
benchmarking tool account.
(f) To ensure the validity and usefulness of covered usage

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data, the utility shall provide the best available consumption
and other information, consistent with the utility's records
as presented to account holders on the utility's customer
portal and captured at the meter level.
(g) Once covered usage data has been made available to a
duly authorized data recipient, such data may not be deleted
or altered by a utility system, except as is necessary to
correct errors or reflect rebills or is affected as part of the
utility's billing data retention policy. If previously
provided covered usage data is changed to correct errors,
notification must be provided to the data recipient.
(h) Within 180 days after the effective date of this Act,
the Commission shall adopt a standard form for a utility
account holder to authorize the sharing of the utility account
holder's covered usage data.
(i) For properties that do not meet the aggregation
threshold and therefore require account holder authorization,
the utility shall provide covered usage data to data
recipients upon account holder authorization, which:
(1) may be provided in Commission-approved form;
(2) may be provided in a lease agreement provision;
and
(3) remains valid until the account holder revokes it,
regardless of how the authorization is provided.
(j) Access to covered usage data under this Section shall
be subject to any rules the Commission has adopted or may

10400HB1700sam002 - 724 - LRB104 08228 AAS 38463 a
choose to adopt, if the rules do not conflict with this
Section.
(k) Except in cases where the utility has not followed
processes established by this Act or the utility is grossly
negligent, the utility shall be held harmless for third-party
misuse of data shared under this Act and no cause of action may
be initiated against the utility for such subsequent misuse.
(l) A utility may file for cost recovery of the reasonable
and prudently incurred costs of providing covered usage data,
including establishing, operating, and maintaining data
aggregation and data access services, for the Commission to
evaluate. A utility shall make good faith efforts to secure
federal, State, or other relevant funding for such investments
in the future. Any such funding the utility receives shall be
deducted from future revenue requirements.
(m) The Commission may hire consultants and experts to
execute their responsibilities under this Act, with the
retention of those consultants and experts exempt from the
requirements of Section 20-10 of the Illinois Procurement
Code.
(Source: P.A. 104-458, eff. 6-1-26.)
Section 35. The Environmental Protection Act is amended by
changing Section 9.15 as follows:
(415 ILCS 5/9.15)

10400HB1700sam002 - 725 - LRB104 08228 AAS 38463 a
(Text of Section before amendment by P.A. 104-458)
Sec. 9.15. Greenhouse gases.
(a) An air pollution construction permit shall not be
required due to emissions of greenhouse gases if the
equipment, site, or source is not subject to regulation, as
defined by 40 CFR 52.21, as now or hereafter amended, for
greenhouse gases or is otherwise not addressed in this Section
or by the Board in regulations for greenhouse gases. These
exemptions do not relieve an owner or operator from the
obligation to comply with other applicable rules or
regulations.
(b) An air pollution operating permit shall not be
required due to emissions of greenhouse gases if the
equipment, site, or source is not subject to regulation, as
defined by Section 39.5 of this Act, for greenhouse gases or is
otherwise not addressed in this Section or by the Board in
regulations for greenhouse gases. These exemptions do not
relieve an owner or operator from the obligation to comply
with other applicable rules or regulations.
(c) (Blank).
(d) (Blank).
(e) (Blank).
(f) As used in this Section:
"Carbon dioxide emission" means the plant annual CO2 total
output emission as measured by the United States Environmental
Protection Agency in its Emissions & Generation Resource

10400HB1700sam002 - 726 - LRB104 08228 AAS 38463 a
Integrated Database (eGrid), or its successor.
"Carbon dioxide equivalent emissions" or "CO2e" means the
sum total of the mass amount of emissions in tons per year,
calculated by multiplying the mass amount of each of the 6
greenhouse gases specified in Section 3.207, in tons per year,
by its associated global warming potential as set forth in 40
CFR 98, subpart A, table A-1 or its successor, and then adding
them all together.
"Cogeneration" or "combined heat and power" refers to any
system that, either simultaneously or sequentially, produces
electricity and useful thermal energy from a single fuel
source.
"Copollutants" refers to the 6 criteria pollutants that
have been identified by the United States Environmental
Protection Agency pursuant to the Clean Air Act.
"Electric generating unit" or "EGU" means a fossil
fuel-fired stationary boiler, combustion turbine, or combined
cycle system that serves a generator that has a nameplate
capacity greater than 25 MWe and produces electricity for
sale.
"Environmental justice community" means the definition of
that term based on existing methodologies and findings, used
and as may be updated by the Illinois Power Agency and its
program administrator in the Illinois Solar for All Program.
"Equity investment eligible community" or "eligible
community" means the geographic areas throughout Illinois that

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

10400HB1700sam002 - 728 - LRB104 08228 AAS 38463 a
unit or mine is in the process of closing or closed within
the last 5 years;
(3) persons who are graduates of or currently enrolled
in the foster care system; or
(4) persons who were formerly incarcerated.
"Existing emissions" means:
(1) for CO2e, the total average tons-per-year of CO2e
emitted by the EGU or large GHG-emitting unit either in
the years 2018 through 2020 or, if the unit was not yet in
operation by January 1, 2018, in the first 3 full years of
that unit's operation; and
(2) for any copollutant, the total average
tons-per-year of that copollutant emitted by the EGU or
large GHG-emitting unit either in the years 2018 through
2020 or, if the unit was not yet in operation by January 1,
2018, in the first 3 full years of that unit's operation.
"Green hydrogen" means a power plant technology in which
an EGU creates electric power exclusively from electrolytic
hydrogen, in a manner that produces zero carbon and
copollutant emissions, using hydrogen fuel that is
electrolyzed using a 100% renewable zero carbon emission
energy source.
"Large greenhouse gas-emitting unit" or "large
GHG-emitting unit" means a unit that is an electric generating
unit or other fossil fuel-fired unit that itself has a
nameplate capacity or serves a generator that has a nameplate

10400HB1700sam002 - 729 - LRB104 08228 AAS 38463 a
capacity greater than 25 MWe and that produces electricity,
including, but not limited to, coal-fired, coal-derived,
oil-fired, natural gas-fired, and cogeneration units.
"NOx emission rate" means the plant annual NOx total output
emission rate as measured by the United States Environmental
Protection Agency in its Emissions & Generation Resource
Integrated Database (eGrid), or its successor, in the most
recent year for which data is available.
"Public greenhouse gas-emitting units" or "public
GHG-emitting unit" means large greenhouse gas-emitting units,
including EGUs, that are wholly owned, directly or indirectly,
by one or more municipalities, municipal corporations, joint
municipal electric power agencies, electric cooperatives, or
other governmental or nonprofit entities, whether organized
and created under the laws of Illinois or another state.
"SO2 emission rate" means the "plant annual SO2 total
output emission rate" as measured by the United States
Environmental Protection Agency in its Emissions & Generation
Resource Integrated Database (eGrid), or its successor, in the
most recent year for which data is available.
(g) All EGUs and large greenhouse gas-emitting units that
use coal or oil as a fuel and are not public GHG-emitting units
shall permanently reduce all CO2e and copollutant emissions to
zero no later than January 1, 2030.
(h) All EGUs and large greenhouse gas-emitting units that
use coal as a fuel and are public GHG-emitting units shall

10400HB1700sam002 - 730 - LRB104 08228 AAS 38463 a
permanently reduce CO2e emissions to zero no later than
December 31, 2045. Any source or plant with such units must
also reduce their CO2e emissions by 45% from existing
emissions by no later than January 1, 2035. If the emissions
reduction requirement is not achieved by December 31, 2035,
the plant shall retire one or more units or otherwise reduce
its CO2e emissions by 45% from existing emissions by June 30,
2038.
(i) All EGUs and large greenhouse gas-emitting units that
use gas as a fuel and are not public GHG-emitting units shall
permanently reduce all CO2e and copollutant emissions to zero,
including through unit retirement or the use of 100% green
hydrogen or other similar technology that is commercially
proven to achieve zero carbon emissions, according to the
following:
(1) No later than January 1, 2030: all EGUs and large
greenhouse gas-emitting units that have a NOx emissions
rate of greater than 0.12 lbs/MWh or a SO2 emission rate of
greater than 0.006 lb/MWh, and are located in or within 3
miles of an environmental justice community designated as
of January 1, 2021 or an equity investment eligible
community.
(2) No later than January 1, 2040: all EGUs and large
greenhouse gas-emitting units that have a NOx emission
rate of greater than 0.12 lbs/MWh or a SO2 emission rate
greater than 0.006 lb/MWh, and are not located in or

10400HB1700sam002 - 731 - LRB104 08228 AAS 38463 a
within 3 miles of an environmental justice community
designated as of January 1, 2021 or an equity investment
eligible community. After January 1, 2035, each such EGU
and large greenhouse gas-emitting unit shall reduce its
CO2e emissions by at least 50% from its existing emissions
for CO2e, and shall be limited in operation to, on average,
6 hours or less per day, measured over a calendar year, and
shall not run for more than 24 consecutive hours except in
emergency conditions, as designated by a Regional
Transmission Organization or Independent System Operator.
(3) No later than January 1, 2035: all EGUs and large
greenhouse gas-emitting units that began operation prior
to the effective date of this amendatory Act of the 102nd
General Assembly and have a NOx emission rate of less than
or equal to 0.12 lb/MWh and a SO2 emission rate less than
or equal to 0.006 lb/MWh, and are located in or within 3
miles of an environmental justice community designated as
of January 1, 2021 or an equity investment eligible
community. Each such EGU and large greenhouse gas-emitting
unit shall reduce its CO2e emissions by at least 50% from
its existing emissions for CO2e no later than January 1,
2030.
(4) No later than January 1, 2040: All remaining EGUs
and large greenhouse gas-emitting units that have a heat
rate greater than or equal to 7000 BTU/kWh. Each such EGU
and Large greenhouse gas-emitting unit shall reduce its

10400HB1700sam002 - 732 - LRB104 08228 AAS 38463 a
CO2e emissions by at least 50% from its existing emissions
for CO2e no later than January 1, 2035.
(5) No later than January 1, 2045: all remaining EGUs
and large greenhouse gas-emitting units.
(j) All EGUs and large greenhouse gas-emitting units that
use gas as a fuel and are public GHG-emitting units shall
permanently reduce all CO2e and copollutant emissions to zero,
including through unit retirement or the use of 100% green
hydrogen or other similar technology that is commercially
proven to achieve zero carbon emissions by January 1, 2045.
(k) All EGUs and large greenhouse gas-emitting units that
utilize combined heat and power or cogeneration technology
shall permanently reduce all CO2e and copollutant emissions to
zero, including through unit retirement or the use of 100%
green hydrogen or other similar technology that is
commercially proven to achieve zero carbon emissions by
January 1, 2045.
(k-5) No EGU or large greenhouse gas-emitting unit that
uses gas as a fuel and is not a public GHG-emitting unit may
emit, in any 12-month period, CO2e or copollutants in excess of
that unit's existing emissions for those pollutants.
(l) Notwithstanding subsections (g) through (k-5), large
GHG-emitting units including EGUs may temporarily continue
emitting CO2e and copollutants after any applicable deadline
specified in any of subsections (g) through (k-5) if it has
been determined, as described in paragraphs (1) and (2) of

10400HB1700sam002 - 733 - LRB104 08228 AAS 38463 a
this subsection, that ongoing operation of the EGU is
necessary to maintain power grid supply and reliability or
ongoing operation of large GHG-emitting unit that is not an
EGU is necessary to serve as an emergency backup to
operations. Up to and including the occurrence of an emission
reduction deadline under subsection (i), all EGUs and large
GHG-emitting units must comply with the following terms:
(1) if an EGU or large GHG-emitting unit that is a
participant in a regional transmission organization
intends to retire, it must submit documentation to the
appropriate regional transmission organization by the
appropriate deadline that meets all applicable regulatory
requirements necessary to obtain approval to permanently
cease operating the large GHG-emitting unit;
(2) if any EGU or large GHG-emitting unit that is a
participant in a regional transmission organization
receives notice that the regional transmission
organization has determined that continued operation of
the unit is required, the unit may continue operating
until the issue identified by the regional transmission
organization is resolved. The owner or operator of the
unit must cooperate with the regional transmission
organization in resolving the issue and must reduce its
emissions to zero, consistent with the requirements under
subsection (g), (h), (i), (j), (k), or (k-5), as
applicable, as soon as practicable when the issue

10400HB1700sam002 - 734 - LRB104 08228 AAS 38463 a
identified by the regional transmission organization is
resolved; and
(3) any large GHG-emitting unit that is not a
participant in a regional transmission organization shall
be allowed to continue emitting CO2e and copollutants
after the zero-emission date specified in subsection (g),
(h), (i), (j), (k), or (k-5), as applicable, in the
capacity of an emergency backup unit if approved by the
Illinois Commerce Commission.
(m) No variance, adjusted standard, or other regulatory
relief otherwise available in this Act may be granted to the
emissions reduction and elimination obligations in this
Section.
(n) By June 30 of each year, beginning in 2025, the Agency
shall prepare and publish on its website a report setting
forth the actual greenhouse gas emissions from individual
units and the aggregate statewide emissions from all units for
the prior year.
(o) Every 5 years beginning in 2025, the Environmental
Protection Agency, Illinois Power Agency, and Illinois
Commerce Commission shall jointly prepare, and release
publicly, a report to the General Assembly that examines the
State's current progress toward its renewable energy resource
development goals, the status of CO2e and copollutant
emissions reductions, the current status and progress toward
developing and implementing green hydrogen technologies, the

10400HB1700sam002 - 735 - LRB104 08228 AAS 38463 a
current and projected status of electric resource adequacy and
reliability throughout the State for the period beginning 5
years ahead, and proposed solutions for any findings. The
Environmental Protection Agency, Illinois Power Agency, and
Illinois Commerce Commission shall consult PJM
Interconnection, LLC and Midcontinent Independent System
Operator, Inc., or their respective successor organizations
regarding forecasted resource adequacy and reliability needs,
anticipated new generation interconnection, new transmission
development or upgrades, and any announced large GHG-emitting
unit closure dates and include this information in the report.
The report shall be released publicly by no later than
December 15 of the year it is prepared. If the Environmental
Protection Agency, Illinois Power Agency, and Illinois
Commerce Commission jointly conclude in the report that the
data from the regional grid operators, the pace of renewable
energy development, the pace of development of energy storage
and demand response utilization, transmission capacity, and
the CO2e and copollutant emissions reductions required by
subsection (i) or (k-5) reasonably demonstrate that a resource
adequacy shortfall will occur, including whether there will be
sufficient in-state capacity to meet the zonal requirements of
MISO Zone 4 or the PJM ComEd Zone, per the requirements of the
regional transmission organizations, or that the regional
transmission operators determine that a reliability violation
will occur during the time frame the study is evaluating, then

10400HB1700sam002 - 736 - LRB104 08228 AAS 38463 a
the Illinois Power Agency, in conjunction with the
Environmental Protection Agency shall develop a plan to reduce
or delay CO2e and copollutant emissions reductions
requirements only to the extent and for the duration necessary
to meet the resource adequacy and reliability needs of the
State, including allowing any plants whose emission reduction
deadline has been identified in the plan as creating a
reliability concern to continue operating, including operating
with reduced emissions or as emergency backup where
appropriate. The plan shall also consider the use of renewable
energy, energy storage, demand response, transmission
development, or other strategies to resolve the identified
resource adequacy shortfall or reliability violation.
(1) In developing the plan, the Environmental
Protection Agency and the Illinois Power Agency shall hold
at least one workshop open to, and accessible at a time and
place convenient to, the public and shall consider any
comments made by stakeholders or the public. Upon
development of the plan, copies of the plan shall be
posted and made publicly available on the Environmental
Protection Agency's, the Illinois Power Agency's, and the
Illinois Commerce Commission's websites. All interested
parties shall have 60 days following the date of posting
to provide comment to the Environmental Protection Agency
and the Illinois Power Agency on the plan. All comments
submitted to the Environmental Protection Agency and the

10400HB1700sam002 - 737 - LRB104 08228 AAS 38463 a
Illinois Power Agency shall be encouraged to be specific,
supported by data or other detailed analyses, and, if
objecting to all or a portion of the plan, accompanied by
specific alternative wording or proposals. All comments
shall be posted on the Environmental Protection Agency's,
the Illinois Power Agency's, and the Illinois Commerce
Commission's websites. Within 30 days following the end of
the 60-day review period, the Environmental Protection
Agency and the Illinois Power Agency shall revise the plan
as necessary based on the comments received and file its
revised plan with the Illinois Commerce Commission for
approval.
(2) Within 60 days after the filing of the revised
plan at the Illinois Commerce Commission, any person
objecting to the plan shall file an objection with the
Illinois Commerce Commission. Within 30 days after the
expiration of the comment period, the Illinois Commerce
Commission shall determine whether an evidentiary hearing
is necessary. The Illinois Commerce Commission shall also
host 3 public hearings within 90 days after the plan is
filed. Following the evidentiary and public hearings, the
Illinois Commerce Commission shall enter its order
approving or approving with modifications the reliability
mitigation plan within 180 days.
(3) The Illinois Commerce Commission shall only
approve the plan if the Illinois Commerce Commission

10400HB1700sam002 - 738 - LRB104 08228 AAS 38463 a
determines that it will resolve the resource adequacy or
reliability deficiency identified in the reliability
mitigation plan at the least amount of CO2e and copollutant
emissions, taking into consideration the emissions impacts
on environmental justice communities, and that it will
ensure adequate, reliable, affordable, efficient, and
environmentally sustainable electric service at the lowest
total cost over time, taking into account the impact of
increases in emissions.
(4) If the resource adequacy or reliability deficiency
identified in the reliability mitigation plan is resolved
or reduced, the Environmental Protection Agency and the
Illinois Power Agency may file an amended plan adjusting
the reduction or delay in CO2e and copollutant emission
reduction requirements identified in the plan.
(Source: P.A. 102-662, eff. 9-15-21; 102-1031, eff. 5-27-22.)
(Text of Section after amendment by P.A. 104-458)
Sec. 9.15. Greenhouse gases.
(a) An air pollution construction permit shall not be
required due to emissions of greenhouse gases if the
equipment, site, or source is not subject to regulation, as
defined by 40 CFR 52.21, as now or hereafter amended, for
greenhouse gases or is otherwise not addressed in this Section
or by the Board in regulations for greenhouse gases. These
exemptions do not relieve an owner or operator from the

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obligation to comply with other applicable rules or
regulations.
(b) An air pollution operating permit shall not be
required due to emissions of greenhouse gases if the
equipment, site, or source is not subject to regulation, as
defined by Section 39.5 of this Act, for greenhouse gases or is
otherwise not addressed in this Section or by the Board in
regulations for greenhouse gases. These exemptions do not
relieve an owner or operator from the obligation to comply
with other applicable rules or regulations.
(c) (Blank).
(d) (Blank).
(e) (Blank).
(f) As used in this Section:
"Carbon dioxide emission" means the plant annual CO2 total
output emission as measured by the United States Environmental
Protection Agency in its Emissions & Generation Resource
Integrated Database (eGrid), or its successor.
"Carbon dioxide equivalent emissions" or "CO2e" means the
sum total of the mass amount of emissions in tons per year,
calculated by multiplying the mass amount of each of the 6
greenhouse gases specified in Section 3.207, in tons per year,
by its associated global warming potential as set forth in 40
CFR 98, subpart A, table A-1 or its successor, and then adding
them all together.
"Cogeneration" or "combined heat and power" refers to any

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system that, either simultaneously or sequentially, produces
electricity and useful thermal energy from a single fuel
source.
"Copollutants" refers to the 6 criteria pollutants that
have been identified by the United States Environmental
Protection Agency pursuant to the Clean Air Act.
"Electric generating unit" or "EGU" means a fossil
fuel-fired stationary boiler, combustion turbine, or combined
cycle system that serves a generator that has a nameplate
capacity greater than 25 MWe and produces electricity for
sale.
"Environmental justice community" means the definition of
that term based on existing methodologies and findings, used
and as may be updated by the Illinois Power Agency and its
program administrator in the Illinois Solar for All Program.
"Equity investment eligible community" or "eligible
community" means the geographic areas throughout Illinois that
would most benefit from equitable investments by the State
designed to combat discrimination and foster sustainable
economic growth. Specifically, eligible community means the
following areas:
(1) areas where residents have been historically
excluded from economic opportunities, including
opportunities in the energy sector, as defined as R3 areas
pursuant to Section 10-40 of the Cannabis Regulation and
Tax Act; and

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(2) areas where residents have been historically
subject to disproportionate burdens of pollution,
including pollution from the energy sector, as established
by environmental justice communities as defined by the
Illinois Power Agency pursuant to the Illinois Power
Agency Act, excluding any racial or ethnic indicators.
"Equity investment eligible person" or "eligible person"
means the persons who would most benefit from equitable
investments by the State designed to combat discrimination and
foster sustainable economic growth. Specifically, eligible
person means the following people:
(1) persons whose primary residence is in an equity
investment eligible community;
(2) persons whose primary residence is in a
municipality, or a county with a population under 100,000,
where the closure of an electric generating unit or mine
has been publicly announced or the electric generating
unit or mine is in the process of closing or closed within
the last 5 years;
(3) persons who are graduates of or currently enrolled
in the foster care system; or
(4) persons who were formerly incarcerated.
"Existing emissions" means:
(1) for CO2e, the total average tons-per-year of CO2e
emitted by the EGU or large GHG-emitting unit either in
the years 2018 through 2020 or, if the unit was not yet in

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operation by January 1, 2018, in the first 3 full years of
that unit's operation; and
(2) for any copollutant, the total average
tons-per-year of that copollutant emitted by the EGU or
large GHG-emitting unit either in the years 2018 through
2020 or, if the unit was not yet in operation by January 1,
2018, in the first 3 full years of that unit's operation.
"Green hydrogen" means a power plant technology in which
an EGU creates electric power exclusively from electrolytic
hydrogen, in a manner that produces zero carbon and
copollutant emissions, using hydrogen fuel that is
electrolyzed using a 100% renewable zero carbon emission
energy source.
"Large greenhouse gas-emitting unit" or "large
GHG-emitting unit" means a unit that is an electric generating
unit or other fossil fuel-fired unit that itself has a
nameplate capacity or serves a generator that has a nameplate
capacity greater than 25 MWe and that produces electricity,
including, but not limited to, coal-fired, coal-derived,
oil-fired, natural gas-fired, and cogeneration units.
"NOx emission rate" means the plant annual NOx total output
emission rate as measured by the United States Environmental
Protection Agency in its Emissions & Generation Resource
Integrated Database (eGrid), or its successor, in the most
recent year for which data is available.
"Public greenhouse gas-emitting units" or "public

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GHG-emitting unit" means large greenhouse gas-emitting units,
including EGUs, that are wholly owned, directly or indirectly,
by one or more municipalities, municipal corporations, joint
municipal electric power agencies, electric cooperatives, or
other governmental or nonprofit entities, whether organized
and created under the laws of Illinois or another state.
"SO2 emission rate" means the "plant annual SO2 total
output emission rate" as measured by the United States
Environmental Protection Agency in its Emissions & Generation
Resource Integrated Database (eGrid), or its successor, in the
most recent year for which data is available.
(g) All EGUs and large greenhouse gas-emitting units that
use coal or oil as a fuel and are not public GHG-emitting units
shall permanently reduce all CO2e and copollutant emissions to
zero no later than January 1, 2030.
(h) All EGUs and large greenhouse gas-emitting units that
use coal as a fuel and are public GHG-emitting units shall
permanently reduce CO2e emissions to zero no later than
December 31, 2045. Any source or plant with such units must
also reduce their CO2e emissions by 45% from existing
emissions by no later than January 1, 2035. If the emissions
reduction requirement is not achieved by December 31, 2035,
the plant shall retire one or more units or otherwise reduce
its CO2e emissions by 45% from existing emissions by June 30,
2038.
(i) All EGUs and large greenhouse gas-emitting units that

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use gas as a fuel and are not public GHG-emitting units shall
permanently reduce all CO2e and copollutant emissions to zero,
including through unit retirement or the use of 100% green
hydrogen or other similar technology that is commercially
proven to achieve zero carbon emissions, according to the
following:
(1) No later than January 1, 2030: all EGUs and large
greenhouse gas-emitting units that have a NOx emissions
rate of greater than 0.12 lbs/MWh or a SO2 emission rate of
greater than 0.006 lb/MWh, and are located in or within 3
miles of an environmental justice community designated as
of January 1, 2021 or an equity investment eligible
community.
(2) No later than January 1, 2040: all EGUs and large
greenhouse gas-emitting units that have a NOx emission
rate of greater than 0.12 lbs/MWh or a SO2 emission rate
greater than 0.006 lb/MWh, and are not located in or
within 3 miles of an environmental justice community
designated as of January 1, 2021 or an equity investment
eligible community. After January 1, 2035, each such EGU
and large greenhouse gas-emitting unit shall reduce its
CO2e emissions by at least 50% from its existing emissions
for CO2e, and shall be limited in operation to, on average,
6 hours or less per day, measured over a calendar year, and
shall not run for more than 24 consecutive hours except in
emergency conditions, as designated by a Regional

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Transmission Organization or Independent System Operator.
(3) No later than January 1, 2035: all EGUs and large
greenhouse gas-emitting units that began operation prior
to the effective date of this amendatory Act of the 102nd
General Assembly and have a NOx emission rate of less than
or equal to 0.12 lb/MWh and a SO2 emission rate less than
or equal to 0.006 lb/MWh, and are located in or within 3
miles of an environmental justice community designated as
of January 1, 2021 or an equity investment eligible
community. Each such EGU and large greenhouse gas-emitting
unit shall reduce its CO2e emissions by at least 50% from
its existing emissions for CO2e no later than January 1,
2030.
(4) No later than January 1, 2040: All remaining EGUs
and large greenhouse gas-emitting units that have a heat
rate greater than or equal to 7000 BTU/kWh. Each such EGU
and Large greenhouse gas-emitting unit shall reduce its
CO2e emissions by at least 50% from its existing emissions
for CO2e no later than January 1, 2035.
(5) No later than January 1, 2045: all remaining EGUs
and large greenhouse gas-emitting units.
(j) All EGUs and large greenhouse gas-emitting units that
use gas as a fuel and are public GHG-emitting units shall
permanently reduce all CO2e and copollutant emissions to zero,
including through unit retirement or the use of 100% green
hydrogen or other similar technology that is commercially

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proven to achieve zero carbon emissions by January 1, 2045.
(k) All EGUs and large greenhouse gas-emitting units that
utilize combined heat and power or cogeneration technology
shall permanently reduce all CO2e and copollutant emissions to
zero, including through unit retirement or the use of 100%
green hydrogen or other similar technology that is
commercially proven to achieve zero carbon emissions by
January 1, 2045.
(k-5) No EGU or large greenhouse gas-emitting unit that
uses gas as a fuel and is not a public GHG-emitting unit may
emit, in any 12-month period, CO2e or copollutants in excess of
that unit's existing emissions for those pollutants.
(l) Notwithstanding subsections (g) through (k-5), large
GHG-emitting units including EGUs may temporarily continue
emitting CO2e and copollutants after any applicable deadline
specified in any of subsections (g) through (k-5) if it has
been determined, as described in paragraphs (1) and (2) of
this subsection, that ongoing operation of the EGU is
necessary to maintain power grid supply and reliability or
ongoing operation of large GHG-emitting unit that is not an
EGU is necessary to serve as an emergency backup to
operations. Up to and including the occurrence of an emission
reduction deadline under subsection (i), all EGUs and large
GHG-emitting units must comply with the following terms:
(1) if an EGU or large GHG-emitting unit that is a
participant in a regional transmission organization

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intends to retire, it must submit documentation to the
appropriate regional transmission organization by the
appropriate deadline that meets all applicable regulatory
requirements necessary to obtain approval to permanently
cease operating the large GHG-emitting unit;
(2) if any EGU or large GHG-emitting unit that is a
participant in a regional transmission organization
receives notice that the regional transmission
organization has determined that continued operation of
the unit is required, the unit may continue operating
until the issue identified by the regional transmission
organization is resolved. The owner or operator of the
unit must cooperate with the regional transmission
organization in resolving the issue and must reduce its
emissions to zero, consistent with the requirements under
subsection (g), (h), (i), (j), (k), or (k-5), as
applicable, as soon as practicable when the issue
identified by the regional transmission organization is
resolved; and
(3) any large GHG-emitting unit that is not a
participant in a regional transmission organization shall
be allowed to continue emitting CO2e and copollutants
after the zero-emission date specified in subsection (g),
(h), (i), (j), (k), or (k-5), as applicable, in the
capacity of an emergency backup unit if approved by the
Illinois Commerce Commission.

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(m) No variance, adjusted standard, or other regulatory
relief otherwise available in this Act may be granted to the
emissions reduction and elimination obligations in this
Section.
(n) By June 30 of each year, beginning in 2025, the Agency
shall prepare and publish on its website a report setting
forth the actual greenhouse gas emissions from individual
units and the aggregate statewide emissions from all units for
the prior year.
(o) The Environmental Protection Agency, Illinois Power
Agency, and Illinois Commerce Commission shall jointly
prepare, and release publicly, a report to the General
Assembly that examines the State's current progress toward its
renewable energy resource development goals, the status of
CO2e and copollutant emissions reductions, the current status
and progress toward developing and implementing green hydrogen
technologies, the current and projected status of electric
resource adequacy and reliability throughout the State for the
period beginning 5 years ahead, and proposed solutions for any
findings. The Environmental Protection Agency, Illinois Power
Agency, and Illinois Commerce Commission shall consult PJM
Interconnection, LLC and Midcontinent Independent System
Operator, Inc., or their respective successor organizations
regarding forecasted resource adequacy and reliability needs,
anticipated new generation interconnection, new transmission
development or upgrades, and any announced large GHG-emitting

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unit closure dates and include this information in the report.
The report shall be released publicly by no later than
December 15 of the year it is prepared. If the Environmental
Protection Agency, Illinois Power Agency, and Illinois
Commerce Commission jointly conclude in the report that the
data from the regional grid operators, the pace of renewable
energy development, the pace of development of energy storage
and demand response utilization, transmission capacity, and
the CO2e and copollutant emissions reductions required by
subsection (i) or (k-5) reasonably demonstrate that a resource
adequacy shortfall will occur, including whether there will be
sufficient in-state capacity to meet the zonal requirements of
MISO Zone 4 or the PJM ComEd Zone, per the requirements of the
regional transmission organizations, or that the regional
transmission operators determine that a reliability violation
will occur during the time frame the study is evaluating, then
the Illinois Power Agency, in conjunction with the
Environmental Protection Agency shall develop a plan to reduce
or delay CO2e and copollutant emissions reductions
requirements only to the extent and for the duration necessary
to meet the resource adequacy and reliability needs of the
State, including allowing any plants whose emission reduction
deadline has been identified in the plan as creating a
reliability concern to continue operating, including operating
with reduced emissions or as emergency backup where
appropriate. The plan shall also consider the use of renewable

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energy, energy storage, demand response, transmission
development, or other strategies to resolve the identified
resource adequacy shortfall or reliability violation.
(1) In developing the plan, the Environmental
Protection Agency and the Illinois Power Agency shall hold
at least one workshop open to, and accessible at a time and
place convenient to, the public and shall consider any
comments made by stakeholders or the public. Upon
development of the plan, copies of the plan shall be
posted and made publicly available on the Environmental
Protection Agency's, the Illinois Power Agency's, and the
Illinois Commerce Commission's websites. All interested
parties shall have 60 days following the date of posting
to provide comment to the Environmental Protection Agency
and the Illinois Power Agency on the plan. All comments
submitted to the Environmental Protection Agency and the
Illinois Power Agency shall be encouraged to be specific,
supported by data or other detailed analyses, and, if
objecting to all or a portion of the plan, accompanied by
specific alternative wording or proposals. All comments
shall be posted on the Environmental Protection Agency's,
the Illinois Power Agency's, and the Illinois Commerce
Commission's websites. Within 30 days following the end of
the 60-day review period, the Environmental Protection
Agency and the Illinois Power Agency shall revise the plan
as necessary based on the comments received and file its

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revised plan with the Illinois Commerce Commission for
approval.
(2) Within 60 days after the filing of the revised
plan at the Illinois Commerce Commission, any person
objecting to the plan shall file an objection with the
Illinois Commerce Commission. Within 30 days after the
expiration of the comment period, the Illinois Commerce
Commission shall determine whether an evidentiary hearing
is necessary. The Illinois Commerce Commission shall also
host 3 public hearings within 90 days after the plan is
filed. Following the evidentiary and public hearings, the
Illinois Commerce Commission shall enter its order
approving or approving with modifications the reliability
mitigation plan within 180 days. The Illinois Commerce
Commission may extend the period of review of the revised
plan for no more than an additional 180 days.
(3) The Illinois Commerce Commission shall only
approve the plan if the Illinois Commerce Commission
determines that it will resolve the resource adequacy or
reliability deficiency identified in the reliability
mitigation plan at the least amount of CO2e and copollutant
emissions, taking into consideration the emissions impacts
on environmental justice communities, and that it will
ensure adequate, reliable, affordable, efficient, and
environmentally sustainable electric service at the lowest
total cost over time, taking into account the impact of

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increases in emissions.
(4) If the resource adequacy or reliability deficiency
identified in the reliability mitigation plan is resolved
or reduced, the Environmental Protection Agency and the
Illinois Power Agency may file an amended plan adjusting
the reduction or delay in CO2e and copollutant emission
reduction requirements identified in the plan.
(Source: P.A. 104-458, eff. 6-1-26.)
Section 95. No acceleration or delay. Where this Act makes
changes in a statute that is represented in this Act by text
that is not yet or no longer in effect (for example, a Section
represented by multiple versions), the use of that text does
not accelerate or delay the taking effect of (i) the changes
made by this Act or (ii) provisions derived from any other
Public Act.".