103RD GENERAL ASSEMBLY
State of Illinois
2023 and 2024
SB2552
 
Introduced 3/23/2023, by Sen. David Koehler
 
SYNOPSIS AS INTRODUCED:



See Index

 Amends the Illinois Power Agency Act. Authorizes the Illinois Power Agency to develop capacity procurement plans and conduct competitive procurement processes for the procurement of capacity needed to ensure environmentally sustainable long-term resource adequacy across the State at the lowest cost over time. Amends the Public Utilities Act. Changes the cumulative persisting annual savings goals for electric utilities that serve less than 3,000,000 retail customers but more than 500,000 retail customers for the years of 2024 through 2030. Provides that the cumulative persisting annual savings goals beyond the year 2030 shall increase by 0.9 (rather than 0.6) percentage points per year. Changes the requirements for submitting proposed plans and funding levels to meet savings goals for an electric utility serving more than 500,000 retail customers (rather than serving less than 3,000,000 retail customers but more than 500,000 retail customers). Provides that an electric utility that has a tariff approved within one year of the
amendatory Act shall also offer
at least one market-based, time-of-use rate for eligible
retail customers that choose to take power and energy supply
service from the utility. Sets forth provisions regarding the Illinois Commerce Commission's powers and duties related to residential time-of-use pricing. Provides that the Illinois Power Agency shall conduct capacity procurement events to procure a target portion of
capacity towards the Planning Reserve Margin Requirement
for all Load Serving Entities serving customers within the Applicable Local Resource Zone and a target portion of
capacity towards the PJM Region Reliability Requirement
for Load Serving Entities serving customers within the
Applicable Locational Deliverability Area. Provides that each capacity procurement event may include
the procurement of capacity through a mix of contracts
with different terms and different initial delivery dates. Sets forth the requirements of prepared capacity procurement plans. Requires each alternative electric supplier to make
payment to an applicable electric utility for capacity,
receive transfers of capacity credits, report capacity
credits procured on its behalf to the applicable regional
transmission organization, and submit the capacity credits to
the applicable regional transmission organization under that
regional transmission organization's rules and procedures. Makes other changes.



LRB103 31416 LNS 59082 b


 
 
A BILL FOR
 


SB2552LRB103 31416 LNS 59082 b



1 AN ACT concerning regulation.


2 Be it enacted by the People of the State of Illinois,

3represented in the General Assembly:



4 Section 5. The Illinois Power Agency Act is amended by 
5changing Section 1-20 as follows:

6 (20 ILCS 3855/1-20)
7 Sec. 1-20. General powers and duties of the Agency. 
8 (a) The Agency is authorized to do each of the following:
9  (1) Develop electricity procurement plans to ensure 
10 adequate, reliable, affordable, efficient, and 
11 environmentally sustainable electric service at the lowest 
12 total cost over time, taking into account any benefits of 
13 price stability, for electric utilities that on December 
14 31, 2005 provided electric service to at least 100,000 
15 customers in Illinois and for small multi-jurisdictional 
16 electric utilities that (A) on December 31, 2005 served 
17 less than 100,000 customers in Illinois and (B) request a 
18 procurement plan for their Illinois jurisdictional load. 
19 Except as provided in paragraph (1.5) of this subsection 
20 (a), the electricity procurement plans shall be updated on 
21 an annual basis and shall include electricity generated 
22 from renewable resources sufficient to achieve the 
23 standards specified in this Act. Beginning with the 
 
 
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1 delivery year commencing June 1, 2017, develop procurement 
2 plans to include zero emission credits generated from zero 
3 emission facilities sufficient to achieve the standards 
4 specified in this Act. Beginning with the delivery year 
5 commencing on June 1, 2022, the Agency is authorized to 
6 develop carbon mitigation credit procurement plans to 
7 include carbon mitigation credits generated from 
8 carbon-free energy resources sufficient to achieve the 
9 standards specified in this Act. 
10  (1.5) Develop a long-term renewable resources 
11 procurement plan in accordance with subsection (c) of 
12 Section 1-75 of this Act for renewable energy credits in 
13 amounts sufficient to achieve the standards specified in 
14 this Act for delivery years commencing June 1, 2017 and 
15 for the programs and renewable energy credits specified in 
16 Section 1-56 of this Act. Electricity procurement plans 
17 for delivery years commencing after May 31, 2017, shall 
18 not include procurement of renewable energy resources. 
19  (2) Conduct competitive procurement processes to 
20 procure the supply resources identified in the electricity 
21 procurement plan, pursuant to Section 16-111.5 of the 
22 Public Utilities Act, and, for the delivery year 
23 commencing June 1, 2017, conduct procurement processes to 
24 procure zero emission credits from zero emission 
25 facilities, under subsection (d-5) of Section 1-75 of this 
26 Act. For the delivery year commencing June 1, 2022, the 
 
 
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1 Agency is authorized to conduct procurement processes to 
2 procure carbon mitigation credits from carbon-free energy 
3 resources, under subsection (d-10) of Section 1-75 of this 
4 Act. 
5  (2.5) Beginning with the procurement for the 2017 
6 delivery year, conduct competitive procurement processes 
7 and implement programs to procure renewable energy credits 
8 identified in the long-term renewable resources 
9 procurement plan developed and approved under subsection 
10 (c) of Section 1-75 of this Act and Section 16-111.5 of the 
11 Public Utilities Act. 
12  (2.10) Oversee the procurement by electric utilities 
13 that served more than 300,000 customers in this State as 
14 of January 1, 2019 of renewable energy credits from new 
15 renewable energy facilities to be installed, along with 
16 energy storage facilities, at or adjacent to the sites of 
17 electric generating facilities that burned coal as their 
18 primary fuel source as of January 1, 2016 in accordance 
19 with subsection (c-5) of Section 1-75 of this Act.
20  (2.15) Beginning with the procurement for the delivery 
21 year commencing June 1, 2025, develop capacity procurement 
22 plans and conduct competitive procurement processes for 
23 the procurement of capacity needed to ensure 
24 environmentally sustainable long-term resource adequacy 
25 across the State, for both distribution utilities and 
26 alternative retail electric suppliers, at the lowest cost 
 
 
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1 over time, while taking into account the benefits of price 
2 stability and the need to ensure the reliability, 
3 adequacy, and resilience of the bulk power generation and 
4 delivery system, as well as the health and safety of State 
5 residents, and the urgent need to address climate change. 
6  (3) Develop electric generation and co-generation 
7 facilities that use indigenous coal or renewable 
8 resources, or both, financed with bonds issued by the 
9 Illinois Finance Authority.
10  (4) Supply electricity from the Agency's facilities at 
11 cost to one or more of the following: municipal electric 
12 systems, governmental aggregators, or rural electric 
13 cooperatives in Illinois.
14 (b) Except as otherwise limited by this Act, the Agency 
15has all of the powers necessary or convenient to carry out the 
16purposes and provisions of this Act, including without 
17limitation, each of the following:
18  (1) To have a corporate seal, and to alter that seal at 
19 pleasure, and to use it by causing it or a facsimile to be 
20 affixed or impressed or reproduced in any other manner.
21  (2) To use the services of the Illinois Finance 
22 Authority necessary to carry out the Agency's purposes.
23  (3) To negotiate and enter into loan agreements and 
24 other agreements with the Illinois Finance Authority.
25  (4) To obtain and employ personnel and hire 
26 consultants that are necessary to fulfill the Agency's 
 
 
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1 purposes, and to make expenditures for that purpose within 
2 the appropriations for that purpose.
3  (5) To purchase, receive, take by grant, gift, devise, 
4 bequest, or otherwise, lease, or otherwise acquire, own, 
5 hold, improve, employ, use, and otherwise deal in and 
6 with, real or personal property whether tangible or 
7 intangible, or any interest therein, within the State.
8  (6) To acquire real or personal property, whether 
9 tangible or intangible, including without limitation 
10 property rights, interests in property, franchises, 
11 obligations, contracts, and debt and equity securities, 
12 and to do so by the exercise of the power of eminent domain 
13 in accordance with Section 1-21; except that any real 
14 property acquired by the exercise of the power of eminent 
15 domain must be located within the State.
16  (7) To sell, convey, lease, exchange, transfer, 
17 abandon, or otherwise dispose of, or mortgage, pledge, or 
18 create a security interest in, any of its assets, 
19 properties, or any interest therein, wherever situated.
20  (8) To purchase, take, receive, subscribe for, or 
21 otherwise acquire, hold, make a tender offer for, vote, 
22 employ, sell, lend, lease, exchange, transfer, or 
23 otherwise dispose of, mortgage, pledge, or grant a 
24 security interest in, use, and otherwise deal in and with, 
25 bonds and other obligations, shares, or other securities 
26 (or interests therein) issued by others, whether engaged 
 
 
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1 in a similar or different business or activity.
2  (9) To make and execute agreements, contracts, and 
3 other instruments necessary or convenient in the exercise 
4 of the powers and functions of the Agency under this Act, 
5 including contracts with any person, including personal 
6 service contracts, or with any local government, State 
7 agency, or other entity; and all State agencies and all 
8 local governments are authorized to enter into and do all 
9 things necessary to perform any such agreement, contract, 
10 or other instrument with the Agency. No such agreement, 
11 contract, or other instrument shall exceed 40 years.
12  (10) To lend money, invest and reinvest its funds in 
13 accordance with the Public Funds Investment Act, and take 
14 and hold real and personal property as security for the 
15 payment of funds loaned or invested.
16  (11) To borrow money at such rate or rates of interest 
17 as the Agency may determine, issue its notes, bonds, or 
18 other obligations to evidence that indebtedness, and 
19 secure any of its obligations by mortgage or pledge of its 
20 real or personal property, machinery, equipment, 
21 structures, fixtures, inventories, revenues, grants, and 
22 other funds as provided or any interest therein, wherever 
23 situated.
24  (12) To enter into agreements with the Illinois 
25 Finance Authority to issue bonds whether or not the income 
26 therefrom is exempt from federal taxation.
 
 
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1  (13) To procure insurance against any loss in 
2 connection with its properties or operations in such 
3 amount or amounts and from such insurers, including the 
4 federal government, as it may deem necessary or desirable, 
5 and to pay any premiums therefor.
6  (14) To negotiate and enter into agreements with 
7 trustees or receivers appointed by United States 
8 bankruptcy courts or federal district courts or in other 
9 proceedings involving adjustment of debts and authorize 
10 proceedings involving adjustment of debts and authorize 
11 legal counsel for the Agency to appear in any such 
12 proceedings.
13  (15) To file a petition under Chapter 9 of Title 11 of 
14 the United States Bankruptcy Code or take other similar 
15 action for the adjustment of its debts.
16  (16) To enter into management agreements for the 
17 operation of any of the property or facilities owned by 
18 the Agency.
19  (17) To enter into an agreement to transfer and to 
20 transfer any land, facilities, fixtures, or equipment of 
21 the Agency to one or more municipal electric systems, 
22 governmental aggregators, or rural electric agencies or 
23 cooperatives, for such consideration and upon such terms 
24 as the Agency may determine to be in the best interest of 
25 the residents of Illinois.
26  (18) To enter upon any lands and within any building 
 
 
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1 whenever in its judgment it may be necessary for the 
2 purpose of making surveys and examinations to accomplish 
3 any purpose authorized by this Act.
4  (19) To maintain an office or offices at such place or 
5 places in the State as it may determine.
6  (20) To request information, and to make any inquiry, 
7 investigation, survey, or study that the Agency may deem 
8 necessary to enable it effectively to carry out the 
9 provisions of this Act.
10  (21) To accept and expend appropriations.
11  (22) To engage in any activity or operation that is 
12 incidental to and in furtherance of efficient operation to 
13 accomplish the Agency's purposes, including hiring 
14 employees that the Director deems essential for the 
15 operations of the Agency.
16  (23) To adopt, revise, amend, and repeal rules with 
17 respect to its operations, properties, and facilities as 
18 may be necessary or convenient to carry out the purposes 
19 of this Act, subject to the provisions of the Illinois 
20 Administrative Procedure Act and Sections 1-22 and 1-35 of 
21 this Act.
22  (24) To establish and collect charges and fees as 
23 described in this Act.

24  (25) To conduct competitive gasification feedstock 
25 procurement processes to procure the feedstocks for the 
26 clean coal SNG brownfield facility in accordance with the 
 
 
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1 requirements of Section 1-78 of this Act. 
2  (26) To review, revise, and approve sourcing 
3 agreements and mediate and resolve disputes between gas 
4 utilities and the clean coal SNG brownfield facility 
5 pursuant to subsection (h-1) of Section 9-220 of the 
6 Public Utilities Act. 
7  (27) To request, review and accept proposals, execute 
8 contracts, purchase renewable energy credits and otherwise 
9 dedicate funds from the Illinois Power Agency Renewable 
10 Energy Resources Fund to create and carry out the 
11 objectives of the Illinois Solar for All Program in 
12 accordance with Section 1-56 of this Act. 
13  (28) To ensure Illinois residents and business benefit 
14 from programs administered by the Agency and are properly 
15 protected from any deceptive or misleading marketing 
16 practices by participants in the Agency's programs and 
17 procurements. 
18 (c) In conducting the procurement of electricity or other 
19products, beginning January 1, 2022, the Agency shall not 
20procure any products or services from persons or organizations 
21that are in violation of the Displaced Energy Workers Bill of 
22Rights, as provided under the Energy Community Reinvestment 
23Act at the time of the procurement event or fail to comply the 
24labor standards established in subparagraph (Q) of paragraph 
25(1) of subsection (c) of Section 1-75. 
26(Source: P.A. 102-662, eff. 9-15-21.)

 
 
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1 Section 10. The Public Utilities Act is amended by 
2changing Sections 3-105, 8-103B, 16-111.5, 16-115, and 16-115D 
3and by adding Section 16-107.8 as follows:




4 (220 ILCS 5/3-105) (from Ch. 111 2/3, par. 3-105)



5 Sec. 3-105. Public utility. 
6 (a) "Public utility" means and includes, except where

7otherwise expressly provided in this Section, every 
8corporation, company,
limited liability company, association, 
9joint stock company or association,
firm, partnership or 
10individual, their lessees, trustees, or receivers
appointed by 
11any court whatsoever now or hereafter that owns, controls, 
12operates or manages,
within this State, directly or 
13indirectly, for public use, any plant, equipment
or property 
14used or to be used for or in connection with, or owns or 
15controls or seeks Commission approval to own or control
any 
16franchise, license, permit or right to engage in:


17  (1) the production, storage, transmission, sale, 
18 delivery or furnishing of
heat, cold, power, electricity, 
19 water, or light, except when used solely for

20 communications purposes;


21  (2) the disposal of sewerage; or


22  (3) the conveyance of oil or gas by pipe line.

23 (b) "Public utility" does not include, however:


24  (1) public utilities that are owned and operated by 
 
 
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1 any political
subdivision, public institution of higher 
2 education or municipal
corporation of this State, or 
3 public utilities that are owned by such
political 
4 subdivision, public institution of higher education, or

5 municipal corporation and operated by any of its lessees 
6 or operating agents;


7  (2) water companies which are purely mutual concerns, 
8 having no rates
or charges for services, but paying the 
9 operating expenses by assessment
upon the members of such 
10 a company and no other person;


11  (3) electric cooperatives as defined in Section 3-119;


12  (4) the following natural gas cooperatives:

13   (A) residential natural gas cooperatives that are 
14 not-for-profit
corporations
established for the 
15 purpose of administering and operating, on
a 
16 cooperative basis, the furnishing of natural gas to 
17 residences for the
benefit of their members
who are 
18 residential consumers of natural gas. For
entities 
19 qualifying as residential
natural gas cooperatives and 
20 recognized
by the Illinois Commerce Commission as 
21 such, the State shall guarantee
legally binding 
22 contracts entered into by residential
natural gas

23 cooperatives for the express purpose of acquiring 
24 natural gas supplies for
their members. The Illinois 
25 Commerce Commission shall establish rules and

26 regulations providing for such guarantees. The total 
 
 
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1 liability of the
State in providing all such 
2 guarantees shall not at any time exceed
$1,000,000, 
3 nor shall the State provide such a guarantee to a 
4 residential
natural gas cooperative for more than 3 
5 consecutive years; and

6   (B) natural gas cooperatives that are 
7 not-for-profit corporations operated for the purpose 
8 of administering, on a cooperative basis, the 
9 furnishing of natural gas for the benefit of their 
10 members and that, prior to 90 days after the effective 
11 date of this amendatory Act of the 94th General 
12 Assembly, either had acquired or had entered into an 
13 asset purchase agreement to acquire all or 
14 substantially all of the operating assets of a public 
15 utility or natural gas cooperative with the intention 
16 of operating those assets as a natural gas 
17 cooperative;



18  (5) sewage disposal companies which provide sewage 
19 disposal services
on a mutual basis without establishing 
20 rates or charges for services,
but paying the operating 
21 expenses by assessment upon the members of the
company and 
22 no others;


23  (6) (blank);


24  (7) cogeneration facilities, small power production 
25 facilities, and other
qualifying facilities, as defined in 
26 the Public Utility Regulatory Policies Act
and regulations 
 
 
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1 promulgated thereunder, except to the extent State 
2 regulatory
jurisdiction and action is required or 
3 authorized by federal law, regulations,
regulatory 
4 decisions or the decisions of federal or State courts of 
5 competent
jurisdiction;


6  (8) the ownership or operation of a facility that 
7 sells compressed
natural gas at retail to the public for 
8 use only as a motor vehicle fuel
and the selling of 
9 compressed natural gas at retail to the public for use

10 only as a motor vehicle fuel;


11  (9) alternative retail electric suppliers as defined 
12 in Article XVI; and

13  (10) the Illinois Power Agency.

14 (c) An entity that furnishes the service of charging 
15electric vehicles does not and shall not be deemed to sell 
16electricity and
is not and shall not be deemed a public utility 
17notwithstanding the basis on which the service is provided or 
18billed. If, however, the entity is otherwise deemed a public 
19utility under this Act, or is otherwise
subject to regulation 
20under this Act, then that entity is not exempt
from and remains 
21subject to the otherwise applicable provisions of this Act. 
22The installation, maintenance, and repair of an electric 
23vehicle charging station shall comply with the requirements of 
24subsection (a) of Section 16-128 and Section 16-128A of this 
25Act.
26 For purposes of this subsection, the term "electric 
 
 
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1vehicles" has the
meaning ascribed to that term in Section 10 
2of the Electric Vehicle
Act. 
3(Source: P.A. 97-1128, eff. 8-28-12.)


4 (220 ILCS 5/8-103B)
5 Sec. 8-103B. Energy efficiency and demand-response 
6measures.
7 (a) It is the policy of the State that electric utilities 
8are required to use cost-effective energy efficiency and 
9demand-response measures to reduce delivery load. Requiring 
10investment in cost-effective energy efficiency and 
11demand-response measures will reduce direct and indirect costs 
12to consumers by decreasing environmental impacts and by 
13avoiding or delaying the need for new generation, 
14transmission, and distribution infrastructure. It serves the 
15public interest to allow electric utilities to recover costs 
16for reasonably and prudently incurred expenditures for energy 
17efficiency and demand-response measures. As used in this 
18Section, "cost-effective" means that the measures satisfy the 
19total resource cost test. The low-income measures described in 
20subsection (c) of this Section shall not be required to meet 
21the total resource cost test. For purposes of this Section, 
22the terms "energy-efficiency", "demand-response", "electric 
23utility", and "total resource cost test" have the meanings set 
24forth in the Illinois Power Agency Act. "Black, indigenous, 
25and people of color" and "BIPOC" means people who are members 
 
 
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1of the groups described in subparagraphs (a) through (e) of 
2paragraph (A) of subsection (1) of Section 2 of the Business 
3Enterprise for Minorities, Women, and Persons with 
4Disabilities Act. 
5 (a-5) This Section applies to electric utilities serving 
6more than 500,000 retail customers in the State for those 
7multi-year plans commencing after December 31, 2017. 
8 (b) For purposes of this Section, electric utilities 
9subject to this Section that serve more than 3,000,000 retail 
10customers in the State shall be deemed to have achieved a 
11cumulative persisting annual savings of 6.6% from energy 
12efficiency measures and programs implemented during the period 
13beginning January 1, 2012 and ending December 31, 2017, which 
14percent is based on the deemed average weather normalized 
15sales of electric power and energy during calendar years 2014, 
162015, and 2016 of 88,000,000 MWhs. For the purposes of this 
17subsection (b) and subsection (b-5), the 88,000,000 MWhs of 
18deemed electric power and energy sales shall be reduced by the 
19number of MWhs equal to the sum of the annual consumption of 
20customers that have opted out of subsections (a) through (j) 
21of this Section under paragraph (1) of subsection (l) of this 
22Section, as averaged across the calendar years 2014, 2015, and 
232016. After 2017, the deemed value of cumulative persisting 
24annual savings from energy efficiency measures and programs 
25implemented during the period beginning January 1, 2012 and 
26ending December 31, 2017, shall be reduced each year, as 
 
 
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1follows, and the applicable value shall be applied to and 
2count toward the utility's achievement of the cumulative 
3persisting annual savings goals set forth in subsection (b-5):
4  (1) 5.8% deemed cumulative persisting annual savings 
5 for the year ending December 31, 2018;
6  (2) 5.2% deemed cumulative persisting annual savings 
7 for the year ending December 31, 2019;
8  (3) 4.5% deemed cumulative persisting annual savings 
9 for the year ending December 31, 2020;
10  (4) 4.0% deemed cumulative persisting annual savings 
11 for the year ending December 31, 2021;
12  (5) 3.5% deemed cumulative persisting annual savings 
13 for the year ending December 31, 2022;
14  (6) 3.1% deemed cumulative persisting annual savings 
15 for the year ending December 31, 2023;
16  (7) 2.8% deemed cumulative persisting annual savings 
17 for the year ending December 31, 2024;
18  (8) 2.5% deemed cumulative persisting annual savings 
19 for the year ending December 31, 2025;
20  (9) 2.3% deemed cumulative persisting annual savings 
21 for the year ending December 31, 2026;
22  (10) 2.1% deemed cumulative persisting annual savings 
23 for the year ending December 31, 2027;
24  (11) 1.8% deemed cumulative persisting annual savings 
25 for the year ending December 31, 2028;
26  (12) 1.7% deemed cumulative persisting annual savings 
 
 
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1 for the year ending December 31, 2029;
2  (13) 1.5% deemed cumulative persisting annual savings 
3 for the year ending December 31, 2030;
4  (14) 1.3% deemed cumulative persisting annual savings 
5 for the year ending December 31, 2031;
6  (15) 1.1% deemed cumulative persisting annual savings 
7 for the year ending December 31, 2032;
8  (16) 0.9% deemed cumulative persisting annual savings 
9 for the year ending December 31, 2033;
10  (17) 0.7% deemed cumulative persisting annual savings 
11 for the year ending December 31, 2034;
12  (18) 0.5% deemed cumulative persisting annual savings 
13 for the year ending December 31, 2035;
14  (19) 0.4% deemed cumulative persisting annual savings 
15 for the year ending December 31, 2036;
16  (20) 0.3% deemed cumulative persisting annual savings 
17 for the year ending December 31, 2037;
18  (21) 0.2% deemed cumulative persisting annual savings 
19 for the year ending December 31, 2038;
20  (22) 0.1% deemed cumulative persisting annual savings 
21 for the year ending December 31, 2039; and
22  (23) 0.0% deemed cumulative persisting annual savings 
23 for the year ending December 31, 2040 and all subsequent 
24 years. 
25 For purposes of this Section, "cumulative persisting 
26annual savings" means the total electric energy savings in a 
 
 
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1given year from measures installed in that year or in previous 
2years, but no earlier than January 1, 2012, that are still 
3operational and providing savings in that year because the 
4measures have not yet reached the end of their useful lives.
5 (b-5) Beginning in 2018, electric utilities subject to 
6this Section that serve more than 3,000,000 retail customers 
7in the State shall achieve the following cumulative persisting 
8annual savings goals, as modified by subsection (f) of this 
9Section and as compared to the deemed baseline of 88,000,000 
10MWhs of electric power and energy sales set forth in 
11subsection (b), as reduced by the number of MWhs equal to the 
12sum of the annual consumption of customers that have opted out 
13of subsections (a) through (j) of this Section under paragraph 
14(1) of subsection (l) of this Section as averaged across the 
15calendar years 2014, 2015, and 2016, through the 
16implementation of energy efficiency measures during the 
17applicable year and in prior years, but no earlier than 
18January 1, 2012:
19  (1) 7.8% cumulative persisting annual savings for the 
20 year ending December 31, 2018;
21  (2) 9.1% cumulative persisting annual savings for the 
22 year ending December 31, 2019;
23  (3) 10.4% cumulative persisting annual savings for the 
24 year ending December 31, 2020;
25  (4) 11.8% cumulative persisting annual savings for the 
26 year ending December 31, 2021;
 
 
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1  (5) 13.1% cumulative persisting annual savings for the 
2 year ending December 31, 2022;
3  (6) 14.4% cumulative persisting annual savings for the 
4 year ending December 31, 2023;
5  (7) 15.7% cumulative persisting annual savings for the 
6 year ending December 31, 2024;
7  (8) 17% cumulative persisting annual savings for the 
8 year ending December 31, 2025;
9  (9) 17.9% cumulative persisting annual savings for the 
10 year ending December 31, 2026;
11  (10) 18.8% cumulative persisting annual savings for 
12 the year ending December 31, 2027;
13  (11) 19.7% cumulative persisting annual savings for 
14 the year ending December 31, 2028;
15  (12) 20.6% cumulative persisting annual savings for 
16 the year ending December 31, 2029; and
17  (13) 21.5% cumulative persisting annual savings for 
18 the year ending December 31, 2030.
19 No later than December 31, 2021, the Illinois Commerce 
20Commission shall establish additional cumulative persisting 
21annual savings goals for the years 2031 through 2035. No later 
22than December 31, 2024, the Illinois Commerce Commission shall 
23establish additional cumulative persisting annual savings 
24goals for the years 2036 through 2040. The Commission shall 
25also establish additional cumulative persisting annual savings 
26goals every 5 years thereafter to ensure that utilities always 
 
 
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1have goals that extend at least 11 years into the future. The 
2cumulative persisting annual savings goals beyond the year 
32030 shall increase by 0.9 percentage points per year, absent 
4a Commission decision to initiate a proceeding to consider 
5establishing goals that increase by more or less than that 
6amount. Such a proceeding must be conducted in accordance with 
7the procedures described in subsection (f) of this Section. If 
8such a proceeding is initiated, the cumulative persisting 
9annual savings goals established by the Commission through 
10that proceeding shall reflect the Commission's best estimate 
11of the maximum amount of additional savings that are forecast 
12to be cost-effectively achievable unless such best estimates 
13would result in goals that represent less than 0.5 percentage 
14point annual increases in total cumulative persisting annual 
15savings. The Commission may only establish goals that 
16represent less than 0.5 percentage point annual increases in 
17cumulative persisting annual savings if it can demonstrate, 
18based on clear and convincing evidence and through independent 
19analysis, that 0.5 percentage point increases are not 
20cost-effectively achievable. The Commission shall inform its 
21decision based on an energy efficiency potential study that 
22conforms to the requirements of this Section. 
23 (b-10) For purposes of this Section, electric utilities 
24subject to this Section that serve less than 3,000,000 retail 
25customers but more than 500,000 retail customers in the State 
26shall be deemed to have achieved a cumulative persisting 
 
 
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1annual savings of 6.6% from energy efficiency measures and 
2programs implemented during the period beginning January 1, 
32012 and ending December 31, 2017, which is based on the deemed 
4average weather normalized sales of electric power and energy 
5during calendar years 2014, 2015, and 2016 of 36,900,000 MWhs. 
6For the purposes of this subsection (b-10) and subsection 
7(b-15), the 36,900,000 MWhs of deemed electric power and 
8energy sales shall be reduced by the number of MWhs equal to 
9the sum of the annual consumption of customers that have opted 
10out of subsections (a) through (j) of this Section under 
11paragraph (1) of subsection (l) of this Section, as averaged 
12across the calendar years 2014, 2015, and 2016. After 2017, 
13the deemed value of cumulative persisting annual savings from 
14energy efficiency measures and programs implemented during the 
15period beginning January 1, 2012 and ending December 31, 2017, 
16shall be reduced each year, as follows, and the applicable 
17value shall be applied to and count toward the utility's 
18achievement of the cumulative persisting annual savings goals 
19set forth in subsection (b-15):
20  (1) 5.8% deemed cumulative persisting annual savings 
21 for the year ending December 31, 2018;
22  (2) 5.2% deemed cumulative persisting annual savings 
23 for the year ending December 31, 2019;
24  (3) 4.5% deemed cumulative persisting annual savings 
25 for the year ending December 31, 2020;
26  (4) 4.0% deemed cumulative persisting annual savings 
 
 
SB2552- 22 -LRB103 31416 LNS 59082 b


1 for the year ending December 31, 2021;
2  (5) 3.5% deemed cumulative persisting annual savings 
3 for the year ending December 31, 2022;
4  (6) 3.1% deemed cumulative persisting annual savings 
5 for the year ending December 31, 2023;
6  (7) 2.8% deemed cumulative persisting annual savings 
7 for the year ending December 31, 2024;
8  (8) 2.5% deemed cumulative persisting annual savings 
9 for the year ending December 31, 2025;
10  (9) 2.3% deemed cumulative persisting annual savings 
11 for the year ending December 31, 2026;
12  (10) 2.1% deemed cumulative persisting annual savings 
13 for the year ending December 31, 2027;
14  (11) 1.8% deemed cumulative persisting annual savings 
15 for the year ending December 31, 2028;
16  (12) 1.7% deemed cumulative persisting annual savings 
17 for the year ending December 31, 2029;
18  (13) 1.5% deemed cumulative persisting annual savings 
19 for the year ending December 31, 2030;
20  (14) 1.3% deemed cumulative persisting annual savings 
21 for the year ending December 31, 2031;
22  (15) 1.1% deemed cumulative persisting annual savings 
23 for the year ending December 31, 2032;
24  (16) 0.9% deemed cumulative persisting annual savings 
25 for the year ending December 31, 2033;
26  (17) 0.7% deemed cumulative persisting annual savings 
 
 
SB2552- 23 -LRB103 31416 LNS 59082 b


1 for the year ending December 31, 2034;
2  (18) 0.5% deemed cumulative persisting annual savings 
3 for the year ending December 31, 2035;
4  (19) 0.4% deemed cumulative persisting annual savings 
5 for the year ending December 31, 2036;
6  (20) 0.3% deemed cumulative persisting annual savings 
7 for the year ending December 31, 2037;
8  (21) 0.2% deemed cumulative persisting annual savings 
9 for the year ending December 31, 2038;
10  (22) 0.1% deemed cumulative persisting annual savings 
11 for the year ending December 31, 2039; and
12  (23) 0.0% deemed cumulative persisting annual savings 
13 for the year ending December 31, 2040 and all subsequent 
14 years. 
15 (b-15) Beginning in 2018, electric utilities subject to 
16this Section that serve less than 3,000,000 retail customers 
17but more than 500,000 retail customers in the State shall 
18achieve the following cumulative persisting annual savings 
19goals, as modified by subsection (b-20) and subsection (f) of 
20this Section and as compared to the deemed baseline as reduced 
21by the number of MWhs equal to the sum of the annual 
22consumption of customers that have opted out of subsections 
23(a) through (j) of this Section under paragraph (1) of 
24subsection (l) of this Section as averaged across the calendar 
25years 2014, 2015, and 2016, through the implementation of 
26energy efficiency measures during the applicable year and in 
 
 
SB2552- 24 -LRB103 31416 LNS 59082 b


1prior years, but no earlier than January 1, 2012:
2  (1) 7.4% cumulative persisting annual savings for the 
3 year ending December 31, 2018;
4  (2) 8.2% cumulative persisting annual savings for the 
5 year ending December 31, 2019;
6  (3) 9.0% cumulative persisting annual savings for the 
7 year ending December 31, 2020;
8  (4) 9.8% cumulative persisting annual savings for the 
9 year ending December 31, 2021;
10  (5) 10.6% cumulative persisting annual savings for the 
11 year ending December 31, 2022;
12  (6) 11.4% cumulative persisting annual savings for the 
13 year ending December 31, 2023;
14  (7) 12.8% 12.2% cumulative persisting annual savings 
15 for the year ending December 31, 2024;
16  (8) 14.3% 13% cumulative persisting annual savings for 
17 the year ending December 31, 2025;
18  (9) 15.7% 13.6% cumulative persisting annual savings 
19 for the year ending December 31, 2026;
20  (10) 17.2% 14.2% cumulative persisting annual savings 
21 for the year ending December 31, 2027;
22  (11) 18.6% 14.8% cumulative persisting annual savings 
23 for the year ending December 31, 2028;
24  (12) 20.1% 15.4% cumulative persisting annual savings 
25 for the year ending December 31, 2029; and
26  (13) 21.5% 16% cumulative persisting annual savings 
 
 
SB2552- 25 -LRB103 31416 LNS 59082 b


1 for the year ending December 31, 2030. 
2 No later than December 31, 2021, the Illinois Commerce 
3Commission shall establish additional cumulative persisting 
4annual savings goals for the years 2031 through 2035. No later 
5than December 31, 2024, the Illinois Commerce Commission shall 
6establish additional cumulative persisting annual savings 
7goals for the years 2036 through 2040. The Commission shall 
8also establish additional cumulative persisting annual savings 
9goals every 5 years thereafter to ensure that utilities always 
10have goals that extend at least 11 years into the future. The 
11cumulative persisting annual savings goals beyond the year 
122030 shall increase by 0.9 0.6 percentage points per year, 
13absent a Commission decision to initiate a proceeding to 
14consider establishing goals that increase by more or less than 
15that amount. Such a proceeding must be conducted in accordance 
16with the procedures described in subsection (f) of this 
17Section. If such a proceeding is initiated, the cumulative 
18persisting annual savings goals established by the Commission 
19through that proceeding shall reflect the Commission's best 
20estimate of the maximum amount of additional savings that are 
21forecast to be cost-effectively achievable unless such best 
22estimates would result in goals that represent less than 0.5 
230.4 percentage point annual increases in total cumulative 
24persisting annual savings. The Commission may only establish 
25goals that represent less than 0.5 0.4 percentage point annual 
26increases in cumulative persisting annual savings if it can 
 
 
SB2552- 26 -LRB103 31416 LNS 59082 b


1demonstrate, based on clear and convincing evidence and 
2through independent analysis, that 0.5 0.4 percentage point 
3increases are not cost-effectively achievable. The Commission 
4shall inform its decision based on an energy efficiency 
5potential study that conforms to the requirements of this 
6Section. 
7 (b-20) Each electric utility subject to this Section may 
8include cost-effective voltage optimization measures in its 
9plans submitted under subsections (f) and (g) of this Section, 
10and the costs incurred by a utility to implement the measures 
11under a Commission-approved plan shall be recovered under the 
12provisions of Article IX or Section 16-108.5 of this Act. For 
13purposes of this Section, the measure life of voltage 
14optimization measures shall be 15 years. The measure life 
15period is independent of the depreciation rate of the voltage 
16optimization assets deployed. Utilities may claim savings from 
17voltage optimization on circuits for more than 15 years if 
18they can demonstrate that they have made additional 
19investments necessary to enable voltage optimization savings 
20to continue beyond 15 years. Such demonstrations must be 
21subject to the review of independent evaluation. 
22 Within 270 days after June 1, 2017 (the effective date of 
23Public Act 99-906), an electric utility that serves less than 
243,000,000 retail customers but more than 500,000 retail 
25customers in the State shall file a plan with the Commission 
26that identifies the cost-effective voltage optimization 
 
 
SB2552- 27 -LRB103 31416 LNS 59082 b


1investment the electric utility plans to undertake through 
2December 31, 2024. The Commission, after notice and hearing, 
3shall approve or approve with modification the plan within 120 
4days after the plan's filing and, in the order approving or 
5approving with modification the plan, the Commission shall 
6adjust the applicable cumulative persisting annual savings 
7goals set forth in subsection (b-15) to reflect any amount of 
8cost-effective energy savings approved by the Commission that 
9is greater than or less than the following cumulative 
10persisting annual savings values attributable to voltage 
11optimization for the applicable year:
12  (1) 0.0% of cumulative persisting annual savings for 
13 the year ending December 31, 2018;
14  (2) 0.17% of cumulative persisting annual savings for 
15 the year ending December 31, 2019;
16  (3) 0.17% of cumulative persisting annual savings for 
17 the year ending December 31, 2020;
18  (4) 0.33% of cumulative persisting annual savings for 
19 the year ending December 31, 2021;
20  (5) 0.5% of cumulative persisting annual savings for 
21 the year ending December 31, 2022;
22  (6) 0.67% of cumulative persisting annual savings for 
23 the year ending December 31, 2023;
24  (7) 0.83% of cumulative persisting annual savings for 
25 the year ending December 31, 2024; and
26  (8) 1.0% of cumulative persisting annual savings for 
 
 
SB2552- 28 -LRB103 31416 LNS 59082 b


1 the year ending December 31, 2025 and all subsequent 
2 years. 
3 (b-25) In the event an electric utility jointly offers an 
4energy efficiency measure or program with a gas utility under 
5plans approved under this Section and Section 8-104 of this 
6Act, the electric utility may continue offering the program, 
7including the gas energy efficiency measures, in the event the 
8gas utility discontinues funding the program. In that event, 
9the energy savings value associated with such other fuels 
10shall be converted to electric energy savings on an equivalent 
11Btu basis for the premises. However, the electric utility 
12shall prioritize programs for low-income residential customers 
13to the extent practicable. An electric utility may recover the 
14costs of offering the gas energy efficiency measures under 
15this subsection (b-25).
16 For those energy efficiency measures or programs that save 
17both electricity and other fuels but are not jointly offered 
18with a gas utility under plans approved under this Section and 
19Section 8-104 or not offered with an affiliated gas utility 
20under paragraph (6) of subsection (f) of Section 8-104 of this 
21Act, the electric utility may count savings of fuels other 
22than electricity toward the achievement of its annual savings 
23goal, and the energy savings value associated with such other 
24fuels shall be converted to electric energy savings on an 
25equivalent Btu basis at the premises. 
26 In no event shall more than 10% of each year's applicable 
 
 
SB2552- 29 -LRB103 31416 LNS 59082 b


1annual total savings requirement as defined in paragraph (7.5) 
2of subsection (g) of this Section be met through savings of 
3fuels other than electricity. 
4 (b-27) Beginning in 2022, an electric utility may offer 
5and promote measures that electrify space heating, water 
6heating, cooling, drying, cooking, industrial processes, and 
7other building and industrial end uses that would otherwise be 
8served by combustion of fossil fuel at the premises, provided 
9that the electrification measures reduce total energy 
10consumption at the premises. The electric utility may count 
11the reduction in energy consumption at the premises toward 
12achievement of its annual savings goals. The reduction in 
13energy consumption at the premises shall be calculated as the 
14difference between: (A) the reduction in Btu consumption of 
15fossil fuels as a result of electrification, converted to 
16kilowatt-hour equivalents by dividing by 3,412 Btus Btu's per 
17kilowatt hour; and (B) the increase in kilowatt hours of 
18electricity consumption resulting from the displacement of 
19fossil fuel consumption as a result of electrification. An 
20electric utility may recover the costs of offering and 
21promoting electrification measures under this subsection 
22(b-27).
23 In no event shall electrification savings counted toward 
24each year's applicable annual total savings requirement, as 
25defined in paragraph (7.5) of subsection (g) of this Section, 
26be greater than:
 
 
SB2552- 30 -LRB103 31416 LNS 59082 b


1  (1) 5% per year for each year from 2022 through 2025;
2  (2) 10% per year for each year from 2026 through 2029; 
3 and
4  (3) 15% per year for 2030 and all subsequent years.
5In addition, a minimum of 25% of all electrification savings 
6counted toward a utility's applicable annual total savings 
7requirement must be from electrification of end uses in 
8low-income housing. The limitations on electrification savings 
9that may be counted toward a utility's annual savings goals 
10are separate from and in addition to the subsection (b-25) 
11limitations governing the counting of the other fuel savings 
12resulting from efficiency measures and programs.
13 As part of the annual informational filing to the 
14Commission that is required under paragraph (9) of subsection 
15(g) of this Section, each utility shall identify the specific 
16electrification measures offered under this subsection 
17subjection (b-27); the quantity of each electrification 
18measure that was installed by its customers; the average total 
19cost, average utility cost, average reduction in fossil fuel 
20consumption, and average increase in electricity consumption 
21associated with each electrification measure; the portion of 
22installations of each electrification measure that were in 
23low-income single-family housing, low-income multifamily 
24housing, non-low-income single-family housing, non-low-income 
25multifamily housing, commercial buildings, and industrial 
26facilities; and the quantity of savings associated with each 
 
 
SB2552- 31 -LRB103 31416 LNS 59082 b


1measure category in each customer category that are being 
2counted toward the utility's applicable annual total savings 
3requirement. Prior to installing an electrification measure, 
4the utility shall provide a customer with an estimate of the 
5impact of the new measure on the customer's average monthly 
6electric bill and total annual energy expenses. 
7 (c) Electric utilities shall be responsible for overseeing 
8the design, development, and filing of energy efficiency plans 
9with the Commission and may, as part of that implementation, 
10outsource various aspects of program development and 
11implementation. A minimum of 10%, for electric utilities that 
12serve more than 3,000,000 retail customers in the State, and a 
13minimum of 7%, for electric utilities that serve less than 
143,000,000 retail customers but more than 500,000 retail 
15customers in the State, of the utility's entire portfolio 
16funding level for a given year shall be used to procure 
17cost-effective energy efficiency measures from units of local 
18government, municipal corporations, school districts, public 
19housing, and community college districts, provided that a 
20minimum percentage of available funds shall be used to procure 
21energy efficiency from public housing, which percentage shall 
22be equal to public housing's share of public building energy 
23consumption.
24 The utilities shall also implement energy efficiency 
25measures targeted at low-income households, which, for 
26purposes of this Section, shall be defined as households at or 
 
 
SB2552- 32 -LRB103 31416 LNS 59082 b


1below 80% of area median income, and expenditures to implement 
2the measures shall be no less than $40,000,000 per year for 
3electric utilities that serve more than 3,000,000 retail 
4customers in the State and no less than $13,000,000 per year 
5for electric utilities that serve less than 3,000,000 retail 
6customers but more than 500,000 retail customers in the State. 
7The ratio of spending on efficiency programs targeted at 
8low-income multifamily buildings to spending on efficiency 
9programs targeted at low-income single-family buildings shall 
10be designed to achieve levels of savings from each building 
11type that are approximately proportional to the magnitude of 
12cost-effective lifetime savings potential in each building 
13type. Investment in low-income whole-building weatherization 
14programs shall constitute a minimum of 80% of a utility's 
15total budget specifically dedicated to serving low-income 
16customers.
17 The utilities shall work to bundle low-income energy 
18efficiency offerings with other programs that serve low-income 
19households to maximize the benefits going to these households. 
20The utilities shall market and implement low-income energy 
21efficiency programs in coordination with low-income assistance 
22programs, the Illinois Solar for All Program, and 
23weatherization whenever practicable. The program implementer 
24shall walk the customer through the enrollment process for any 
25programs for which the customer is eligible. The utilities 
26shall also pilot targeting customers with high arrearages, 
 
 
SB2552- 33 -LRB103 31416 LNS 59082 b


1high energy intensity (ratio of energy usage divided by home 
2or unit square footage), or energy assistance programs with 
3energy efficiency offerings, and then track reduction in 
4arrearages as a result of the targeting. This targeting and 
5bundling of low-income energy programs shall be offered to 
6both low-income single-family and multifamily customers 
7(owners and residents). 
8 The utilities shall invest in health and safety measures 
9appropriate and necessary for comprehensively weatherizing a 
10home or multifamily building, and shall implement a health and 
11safety fund of at least 15% of the total income-qualified 
12weatherization budget that shall be used for the purpose of 
13making grants for technical assistance, construction, 
14reconstruction, improvement, or repair of buildings to 
15facilitate their participation in the energy efficiency 
16programs targeted at low-income single-family and multifamily 
17households. These funds may also be used for the purpose of 
18making grants for technical assistance, construction, 
19reconstruction, improvement, or repair of the following 
20buildings to facilitate their participation in the energy 
21efficiency programs created by this Section: (1) buildings 
22that are owned or operated by registered 501(c)(3) public 
23charities; and (2) day care centers, day care homes, or group 
24day care homes, as defined under 89 Ill. Adm. Code Part 406, 
25407, or 408, respectively. 
26 Each electric utility shall assess opportunities to 
 
 
SB2552- 34 -LRB103 31416 LNS 59082 b


1implement cost-effective energy efficiency measures and 
2programs through a public housing authority or authorities 
3located in its service territory. If such opportunities are 
4identified, the utility shall propose such measures and 
5programs to address the opportunities. Expenditures to address 
6such opportunities shall be credited toward the minimum 
7procurement and expenditure requirements set forth in this 
8subsection (c).
9 Implementation of energy efficiency measures and programs 
10targeted at low-income households should be contracted, when 
11it is practicable, to independent third parties that have 
12demonstrated capabilities to serve such households, with a 
13preference for not-for-profit entities and government agencies 
14that have existing relationships with or experience serving 
15low-income communities in the State.
16 Each electric utility shall develop and implement 
17reporting procedures that address and assist in determining 
18the amount of energy savings that can be applied to the 
19low-income procurement and expenditure requirements set forth 
20in this subsection (c). Each electric utility shall also track 
21the types and quantities or volumes of insulation and air 
22sealing materials, and their associated energy saving 
23benefits, installed in energy efficiency programs targeted at 
24low-income single-family and multifamily households. 
25 The electric utilities shall participate in a low-income 
26energy efficiency accountability committee ("the committee"), 
 
 
SB2552- 35 -LRB103 31416 LNS 59082 b


1which will directly inform the design, implementation, and 
2evaluation of the low-income and public-housing energy 
3efficiency programs. The committee shall be comprised of the 
4electric utilities subject to the requirements of this 
5Section, the gas utilities subject to the requirements of 
6Section 8-104 of this Act, the utilities' low-income energy 
7efficiency implementation contractors, nonprofit 
8organizations, community action agencies, advocacy groups, 
9State and local governmental agencies, public-housing 
10organizations, and representatives of community-based 
11organizations, especially those living in or working with 
12environmental justice communities and BIPOC communities. The 
13committee shall be composed of 2 geographically differentiated 
14subcommittees: one for stakeholders in northern Illinois and 
15one for stakeholders in central and southern Illinois. The 
16subcommittees shall meet together at least twice per year.
17 There shall be one statewide leadership committee led by 
18and composed of community-based organizations that are 
19representative of BIPOC and environmental justice communities 
20and that includes equitable representation from BIPOC 
21communities. The leadership committee shall be composed of an 
22equal number of representatives from the 2 subcommittees. The 
23subcommittees shall address specific programs and issues, with 
24the leadership committee convening targeted workgroups as 
25needed. The leadership committee may elect to work with an 
26independent facilitator to solicit and organize feedback, 
 
 
SB2552- 36 -LRB103 31416 LNS 59082 b


1recommendations and meeting participation from a wide variety 
2of community-based stakeholders. If a facilitator is used, 
3they shall be fair and responsive to the needs of all 
4stakeholders involved in the committee.
5  All committee meetings must be accessible, with rotating 
6locations if meetings are held in-person, virtual 
7participation options, and materials and agendas circulated in 
8advance.
9 There shall also be opportunities for direct input by 
10committee members outside of committee meetings, such as via 
11individual meetings, surveys, emails and calls, to ensure 
12robust participation by stakeholders with limited capacity and 
13ability to attend committee meetings. Committee meetings shall 
14emphasize opportunities to bundle and coordinate delivery of 
15low-income energy efficiency with other programs that serve 
16low-income communities, such as the Illinois Solar for All 
17Program and bill payment assistance programs. Meetings shall 
18include educational opportunities for stakeholders to learn 
19more about these additional offerings, and the committee shall 
20assist in figuring out the best methods for coordinated 
21delivery and implementation of offerings when serving 
22low-income communities. The committee shall directly and 
23equitably influence and inform utility low-income and 
24public-housing energy efficiency programs and priorities. 
25Participating utilities shall implement recommendations from 
26the committee whenever possible.
 
 
SB2552- 37 -LRB103 31416 LNS 59082 b


1 Participating utilities shall track and report how input 
2from the committee has led to new approaches and changes in 
3their energy efficiency portfolios. This reporting shall occur 
4at committee meetings and in quarterly energy efficiency 
5reports to the Stakeholder Advisory Group and Illinois 
6Commerce Commission, and other relevant reporting mechanisms. 
7Participating utilities shall also report on relevant equity 
8data and metrics requested by the committee, such as energy 
9burden data, geographic, racial, and other relevant 
10demographic data on where programs are being delivered and 
11what populations programs are serving.
12 The Illinois Commerce Commission shall oversee and have 
13relevant staff participate in the committee. The committee 
14shall have a budget of 0.25% of each utility's entire 
15efficiency portfolio funding for a given year. The budget 
16shall be overseen by the Commission. The budget shall be used 
17to provide grants for community-based organizations serving on 
18the leadership committee, stipends for community-based 
19organizations participating in the committee, grants for 
20community-based organizations to do energy efficiency outreach 
21and education, and relevant meeting needs as determined by the 
22leadership committee. The education and outreach shall 
23include, but is not limited to, basic energy efficiency 
24education, information about low-income energy efficiency 
25programs, and information on the committee's purpose, 
26structure, and activities.
 
 
SB2552- 38 -LRB103 31416 LNS 59082 b


1 (d) Notwithstanding any other provision of law to the 
2contrary, a utility providing approved energy efficiency 
3measures and, if applicable, demand-response measures in the 
4State shall be permitted to recover all reasonable and 
5prudently incurred costs of those measures from all retail 
6customers, except as provided in subsection (l) of this 
7Section, as follows, provided that nothing in this subsection 
8(d) permits the double recovery of such costs from customers: 
9  (1) The utility may recover its costs through an 
10 automatic adjustment clause tariff filed with and approved 
11 by the Commission. The tariff shall be established outside 
12 the context of a general rate case. Each year the 
13 Commission shall initiate a review to reconcile any 
14 amounts collected with the actual costs and to determine 
15 the required adjustment to the annual tariff factor to 
16 match annual expenditures. To enable the financing of the 
17 incremental capital expenditures, including regulatory 
18 assets, for electric utilities that serve less than 
19 3,000,000 retail customers but more than 500,000 retail 
20 customers in the State, the utility's actual year-end 
21 capital structure that includes a common equity ratio, 
22 excluding goodwill, of up to and including 50% of the 
23 total capital structure shall be deemed reasonable and 
24 used to set rates.
25  (2) A utility may recover its costs through an energy 
26 efficiency formula rate approved by the Commission under a 
 
 
SB2552- 39 -LRB103 31416 LNS 59082 b


1 filing under subsections (f) and (g) of this Section, 
2 which shall specify the cost components that form the 
3 basis of the rate charged to customers with sufficient 
4 specificity to operate in a standardized manner and be 
5 updated annually with transparent information that 
6 reflects the utility's actual costs to be recovered during 
7 the applicable rate year, which is the period beginning 
8 with the first billing day of January and extending 
9 through the last billing day of the following December. 
10 The energy efficiency formula rate shall be implemented 
11 through a tariff filed with the Commission under 
12 subsections (f) and (g) of this Section that is consistent 
13 with the provisions of this paragraph (2) and that shall 
14 be applicable to all delivery services customers. The 
15 Commission shall conduct an investigation of the tariff in 
16 a manner consistent with the provisions of this paragraph 
17 (2), subsections (f) and (g) of this Section, and the 
18 provisions of Article IX of this Act to the extent they do 
19 not conflict with this paragraph (2). The energy 
20 efficiency formula rate approved by the Commission shall 
21 remain in effect at the discretion of the utility and 
22 shall do the following:
23   (A) Provide for the recovery of the utility's 
24 actual costs incurred under this Section that are 
25 prudently incurred and reasonable in amount consistent 
26 with Commission practice and law. The sole fact that a 
 
 
SB2552- 40 -LRB103 31416 LNS 59082 b


1 cost differs from that incurred in a prior calendar 
2 year or that an investment is different from that made 
3 in a prior calendar year shall not imply the 
4 imprudence or unreasonableness of that cost or 
5 investment.
6   (B) Reflect the utility's actual year-end capital 
7 structure for the applicable calendar year, excluding 
8 goodwill, subject to a determination of prudence and 
9 reasonableness consistent with Commission practice and 
10 law. To enable the financing of the incremental 
11 capital expenditures, including regulatory assets, for 
12 electric utilities that serve less than 3,000,000 
13 retail customers but more than 500,000 retail 
14 customers in the State, a participating electric 
15 utility's actual year-end capital structure that 
16 includes a common equity ratio, excluding goodwill, of 
17 up to and including 50% of the total capital structure 
18 shall be deemed reasonable and used to set rates.
19   (C) Include a cost of equity, which shall be 
20 calculated as the sum of the following:
21    (i) the average for the applicable calendar 
22 year of the monthly average yields of 30-year U.S. 
23 Treasury bonds published by the Board of Governors 
24 of the Federal Reserve System in its weekly H.15 
25 Statistical Release or successor publication; and
26    (ii) 580 basis points.
 
 
SB2552- 41 -LRB103 31416 LNS 59082 b


1   At such time as the Board of Governors of the 
2 Federal Reserve System ceases to include the monthly 
3 average yields of 30-year U.S. Treasury bonds in its 
4 weekly H.15 Statistical Release or successor 
5 publication, the monthly average yields of the U.S. 
6 Treasury bonds then having the longest duration 
7 published by the Board of Governors in its weekly H.15 
8 Statistical Release or successor publication shall 
9 instead be used for purposes of this paragraph (2).
10   (D) Permit and set forth protocols, subject to a 
11 determination of prudence and reasonableness 
12 consistent with Commission practice and law, for the 
13 following:
14    (i) recovery of incentive compensation expense 
15 that is based on the achievement of operational 
16 metrics, including metrics related to budget 
17 controls, outage duration and frequency, safety, 
18 customer service, efficiency and productivity, and 
19 environmental compliance; however, this protocol 
20 shall not apply if such expense related to costs 
21 incurred under this Section is recovered under 
22 Article IX or Section 16-108.5 of this Act; 
23 incentive compensation expense that is based on 
24 net income or an affiliate's earnings per share 
25 shall not be recoverable under the
energy 
26 efficiency formula rate;
 
 
SB2552- 42 -LRB103 31416 LNS 59082 b


1    (ii) recovery of pension and other 
2 post-employment benefits expense, provided that 
3 such costs are supported by an actuarial study; 
4 however, this protocol shall not apply if such 
5 expense related to costs incurred under this 
6 Section is recovered under Article IX or Section 
7 16-108.5 of this Act;
8    (iii) recovery of existing regulatory assets 
9 over the periods previously authorized by the 
10 Commission;
11    (iv) as described in subsection (e), 
12 amortization of costs incurred under this Section; 
13 and
14    (v) projected, weather normalized billing 
15 determinants for the applicable rate year.
16   (E) Provide for an annual reconciliation, as 
17 described in paragraph (3) of this subsection (d), 
18 less any deferred taxes related to the reconciliation, 
19 with interest at an annual rate of return equal to the 
20 utility's weighted average cost of capital, including 
21 a revenue conversion factor calculated to recover or 
22 refund all additional income taxes that may be payable 
23 or receivable as a result of that return, of the energy 
24 efficiency revenue requirement reflected in rates for 
25 each calendar year, beginning with the calendar year 
26 in which the utility files its energy efficiency 
 
 
SB2552- 43 -LRB103 31416 LNS 59082 b


1 formula rate tariff under this paragraph (2), with 
2 what the revenue requirement would have been had the 
3 actual cost information for the applicable calendar 
4 year been available at the filing date.
5  The utility shall file, together with its tariff, the 
6 projected costs to be incurred by the utility during the 
7 rate year under the utility's multi-year plan approved 
8 under subsections (f) and (g) of this Section, including, 
9 but not limited to, the projected capital investment costs 
10 and projected regulatory asset balances with 
11 correspondingly updated depreciation and amortization 
12 reserves and expense, that shall populate the energy 
13 efficiency formula rate and set the initial rates under 
14 the formula.
15  The Commission shall review the proposed tariff in 
16 conjunction with its review of a proposed multi-year plan, 
17 as specified in paragraph (5) of subsection (g) of this 
18 Section. The review shall be based on the same evidentiary 
19 standards, including, but not limited to, those concerning 
20 the prudence and reasonableness of the costs incurred by 
21 the utility, the Commission applies in a hearing to review 
22 a filing for a general increase in rates under Article IX 
23 of this Act. The initial rates shall take effect beginning 
24 with the January monthly billing period following the 
25 Commission's approval.
26  The tariff's rate design and cost allocation across 
 
 
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1 customer classes shall be consistent with the utility's 
2 automatic adjustment clause tariff in effect on June 1, 
3 2017 (the effective date of Public Act 99-906); however, 
4 the Commission may revise the tariff's rate design and 
5 cost allocation in subsequent proceedings under paragraph 
6 (3) of this subsection (d).
7  If the energy efficiency formula rate is terminated, 
8 the then current rates shall remain in effect until such 
9 time as the energy efficiency costs are incorporated into 
10 new rates that are set under this subsection (d) or 
11 Article IX of this Act, subject to retroactive rate 
12 adjustment, with interest, to reconcile rates charged with 
13 actual costs.
14  (3) The provisions of this paragraph (3) shall only 
15 apply to an electric utility that has elected to file an 
16 energy efficiency formula rate under paragraph (2) of this 
17 subsection (d). Subsequent to the Commission's issuance of 
18 an order approving the utility's energy efficiency formula 
19 rate structure and protocols, and initial rates under 
20 paragraph (2) of this subsection (d), the utility shall 
21 file, on or before June 1 of each year, with the Chief 
22 Clerk of the Commission its updated cost inputs to the 
23 energy efficiency formula rate for the applicable rate 
24 year and the corresponding new charges, as well as the 
25 information described in paragraph (9) of subsection (g) 
26 of this Section. Each such filing shall conform to the 
 
 
SB2552- 45 -LRB103 31416 LNS 59082 b


1 following requirements and include the following 
2 information:
3   (A) The inputs to the energy efficiency formula 
4 rate for the applicable rate year shall be based on the 
5 projected costs to be incurred by the utility during 
6 the rate year under the utility's multi-year plan 
7 approved under subsections (f) and (g) of this 
8 Section, including, but not limited to, projected 
9 capital investment costs and projected regulatory 
10 asset balances with correspondingly updated 
11 depreciation and amortization reserves and expense. 
12 The filing shall also include a reconciliation of the 
13 energy efficiency revenue requirement that was in 
14 effect for the prior rate year (as set by the cost 
15 inputs for the prior rate year) with the actual 
16 revenue requirement for the prior rate year 
17 (determined using a year-end rate base) that uses 
18 amounts reflected in the applicable FERC Form 1 that 
19 reports the actual costs for the prior rate year. Any 
20 over-collection or under-collection indicated by such 
21 reconciliation shall be reflected as a credit against, 
22 or recovered as an additional charge to, respectively, 
23 with interest calculated at a rate equal to the 
24 utility's weighted average cost of capital approved by 
25 the Commission for the prior rate year, the charges 
26 for the applicable rate year. Such over-collection or 
 
 
SB2552- 46 -LRB103 31416 LNS 59082 b


1 under-collection shall be adjusted to remove any 
2 deferred taxes related to the reconciliation, for 
3 purposes of calculating interest at an annual rate of 
4 return equal to the utility's weighted average cost of 
5 capital approved by the Commission for the prior rate 
6 year, including a revenue conversion factor calculated 
7 to recover or refund all additional income taxes that 
8 may be payable or receivable as a result of that 
9 return. Each reconciliation shall be certified by the 
10 participating utility in the same manner that FERC 
11 Form 1 is certified. The filing shall also include the 
12 charge or credit, if any, resulting from the 
13 calculation required by subparagraph (E) of paragraph 
14 (2) of this subsection (d).
15   Notwithstanding any other provision of law to the 
16 contrary, the intent of the reconciliation is to 
17 ultimately reconcile both the revenue requirement 
18 reflected in rates for each calendar year, beginning 
19 with the calendar year in which the utility files its 
20 energy efficiency formula rate tariff under paragraph 
21 (2) of this subsection (d), with what the revenue 
22 requirement determined using a year-end rate base for 
23 the applicable calendar year would have been had the 
24 actual cost information for the applicable calendar 
25 year been available at the filing date.
26   For purposes of this Section, "FERC Form 1" means 
 
 
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1 the Annual Report of Major Electric Utilities, 
2 Licensees and Others that electric utilities are 
3 required to file with the Federal Energy Regulatory 
4 Commission under the Federal Power Act, Sections 3, 
5 4(a), 304 and 209, modified as necessary to be 
6 consistent with 83 Ill. Adm. Admin. Code Part 415 as of 
7 May 1, 2011. Nothing in this Section is intended to 
8 allow costs that are not otherwise recoverable to be 
9 recoverable by virtue of inclusion in FERC Form 1.
10   (B) The new charges shall take effect beginning on 
11 the first billing day of the following January billing 
12 period and remain in effect through the last billing 
13 day of the next December billing period regardless of 
14 whether the Commission enters upon a hearing under 
15 this paragraph (3).
16   (C) The filing shall include relevant and 
17 necessary data and documentation for the applicable 
18 rate year. Normalization adjustments shall not be 
19 required.
20  Within 45 days after the utility files its annual 
21 update of cost inputs to the energy efficiency formula 
22 rate, the Commission shall with reasonable notice, 
23 initiate a proceeding concerning whether the projected 
24 costs to be incurred by the utility and recovered during 
25 the applicable rate year, and that are reflected in the 
26 inputs to the energy efficiency formula rate, are 
 
 
SB2552- 48 -LRB103 31416 LNS 59082 b


1 consistent with the utility's approved multi-year plan 
2 under subsections (f) and (g) of this Section and whether 
3 the costs incurred by the utility during the prior rate 
4 year were prudent and reasonable. The Commission shall 
5 also have the authority to investigate the information and 
6 data described in paragraph (9) of subsection (g) of this 
7 Section, including the proposed adjustment to the 
8 utility's return on equity component of its weighted 
9 average cost of capital. During the course of the 
10 proceeding, each objection shall be stated with 
11 particularity and evidence provided in support thereof, 
12 after which the utility shall have the opportunity to 
13 rebut the evidence. Discovery shall be allowed consistent 
14 with the Commission's Rules of Practice, which Rules of 
15 Practice shall be enforced by the Commission or the 
16 assigned administrative law judge. The Commission shall 
17 apply the same evidentiary standards, including, but not 
18 limited to, those concerning the prudence and 
19 reasonableness of the costs incurred by the utility, 
20 during the proceeding as it would apply in a proceeding to 
21 review a filing for a general increase in rates under 
22 Article IX of this Act. The Commission shall not, however, 
23 have the authority in a proceeding under this paragraph 
24 (3) to consider or order any changes to the structure or 
25 protocols of the energy efficiency formula rate approved 
26 under paragraph (2) of this subsection (d). In a 
 
 
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1 proceeding under this paragraph (3), the Commission shall 
2 enter its order no later than the earlier of 195 days after 
3 the utility's filing of its annual update of cost inputs 
4 to the energy efficiency formula rate or December 15. The 
5 utility's proposed return on equity calculation, as 
6 described in paragraphs (7) through (9) of subsection (g) 
7 of this Section, shall be deemed the final, approved 
8 calculation on December 15 of the year in which it is filed 
9 unless the Commission enters an order on or before 
10 December 15, after notice and hearing, that modifies such 
11 calculation consistent with this Section. The Commission's 
12 determinations of the prudence and reasonableness of the 
13 costs incurred, and determination of such return on equity 
14 calculation, for the applicable calendar year shall be 
15 final upon entry of the Commission's order and shall not 
16 be subject to reopening, reexamination, or collateral 
17 attack in any other Commission proceeding, case, docket, 
18 order, rule, or regulation; however, nothing in this 
19 paragraph (3) shall prohibit a party from petitioning the 
20 Commission to rehear or appeal to the courts the order 
21 under the provisions of this Act.
22 (e)
Beginning on June 1, 2017 (the effective date of 
23Public Act 99-906), a utility subject to the requirements of 
24this Section may elect to defer, as a regulatory asset, up to 
25the full amount of its expenditures incurred under this 
26Section for each annual period, including, but not limited to, 
 
 
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1any expenditures incurred above the funding level set by 
2subsection (f) of this Section for a given year. The total 
3expenditures deferred as a regulatory asset in a given year 
4shall be amortized and recovered over a period that is equal to 
5the weighted average of the energy efficiency measure lives 
6implemented for that year that are reflected in the regulatory 
7asset. The unamortized balance shall be recognized as of 
8December 31 for a given year. The utility shall also earn a 
9return on the total of the unamortized balances of all of the 
10energy efficiency regulatory assets, less any deferred taxes 
11related to those unamortized balances, at an annual rate equal 
12to the utility's weighted average cost of capital that 
13includes, based on a year-end capital structure, the utility's 
14actual cost of debt for the applicable calendar year and a cost 
15of equity, which shall be calculated as the sum of the (i) the 
16average for the applicable calendar year of the monthly 
17average yields of 30-year U.S. Treasury bonds published by the 
18Board of Governors of the Federal Reserve System in its weekly 
19H.15 Statistical Release or successor publication; and (ii) 
20580 basis points, including a revenue conversion factor 
21calculated to recover or refund all additional income taxes 
22that may be payable or receivable as a result of that return. 
23Capital investment costs shall be depreciated and recovered 
24over their useful lives consistent with generally accepted 
25accounting principles. The weighted average cost of capital 
26shall be applied to the capital investment cost balance, less 
 
 
SB2552- 51 -LRB103 31416 LNS 59082 b


1any accumulated depreciation and accumulated deferred income 
2taxes, as of December 31 for a given year.
3 When an electric utility creates a regulatory asset under 
4the provisions of this Section, the costs are recovered over a 
5period during which customers also receive a benefit which is 
6in the public interest. Accordingly, it is the intent of the 
7General Assembly that an electric utility that elects to 
8create a regulatory asset under the provisions of this Section 
9shall recover all of the associated costs as set forth in this 
10Section. After the Commission has approved the prudence and 
11reasonableness of the costs that comprise the regulatory 
12asset, the electric utility shall be permitted to recover all 
13such costs, and the value and recoverability through rates of 
14the associated regulatory asset shall not be limited, altered, 
15impaired, or reduced.
16 (f) Beginning in 2017, each electric utility shall file an 
17energy efficiency plan with the Commission to meet the energy 
18efficiency standards for the next applicable multi-year period 
19beginning January 1 of the year following the filing, 
20according to the schedule set forth in paragraphs (1) through 
21(3) of this subsection (f). If a utility does not file such a 
22plan on or before the applicable filing deadline for the plan, 
23it shall face a penalty of $100,000 per day until the plan is 
24filed.
25  (1) No later than 30 days after June 1, 2017 (the 
26 effective date of Public Act 99-906), each electric 
 
 
SB2552- 52 -LRB103 31416 LNS 59082 b


1 utility shall file a 4-year energy efficiency plan 
2 commencing on January 1, 2018 that is designed to achieve 
3 the cumulative persisting annual savings goals specified 
4 in paragraphs (1) through (4) of subsection (b-5) of this 
5 Section or in paragraphs (1) through (4) of subsection 
6 (b-15) of this Section, as applicable, through 
7 implementation of energy efficiency measures; however, the 
8 goals may be reduced if the utility's expenditures are 
9 limited pursuant to subsection (m) of this Section or, for 
10 a utility that serves less than 3,000,000 retail 
11 customers, if each of the following conditions are met: 
12 (A) the plan's analysis and forecasts of the utility's 
13 ability to acquire energy savings demonstrate that 
14 achievement of such goals is not cost effective; and (B) 
15 the amount of energy savings achieved by the utility as 
16 determined by the independent evaluator for the most 
17 recent year for which savings have been evaluated 
18 preceding the plan filing was less than the average annual 
19 amount of savings required to achieve the goals for the 
20 applicable 4-year plan period. Except as provided in 
21 subsection (m) of this Section, annual increases in 
22 cumulative persisting annual savings goals during the 
23 applicable 4-year plan period shall not be reduced to 
24 amounts that are less than the maximum amount of 
25 cumulative persisting annual savings that is forecast to 
26 be cost-effectively achievable during the 4-year plan 
 
 
SB2552- 53 -LRB103 31416 LNS 59082 b


1 period. The Commission shall review any proposed goal 
2 reduction as part of its review and approval of the 
3 utility's proposed plan.
4  (2) No later than March 1, 2021, each electric utility 
5 shall file a 4-year energy efficiency plan commencing on 
6 January 1, 2022 that is designed to achieve the cumulative 
7 persisting annual savings goals specified in paragraphs 
8 (5) through (8) of subsection (b-5) of this Section or in 
9 paragraphs (5) through (8) of subsection (b-15) of this 
10 Section, as applicable, through implementation of energy 
11 efficiency measures; however, the goals may be reduced if 
12 either (1) clear and convincing evidence demonstrates, 
13 through independent analysis, that the expenditure limits

14 in subsection (m) of this Section preclude full 
15 achievement of the goals or (2) each of the following 
16 conditions are met: (A) the plan's analysis and forecasts 
17 of the utility's ability to acquire energy savings 
18 demonstrate by clear and convincing evidence and through 
19 independent analysis that achievement of such goals is not 
20 cost effective; and (B) the amount of energy savings 
21 achieved by the utility as determined by the independent 
22 evaluator for the most recent year for which savings have 
23 been evaluated preceding the plan filing was less than the 
24 average annual amount of savings required to achieve the 
25 goals for the applicable 4-year plan period. If there is 
26 not clear and convincing evidence that achieving the 
 
 
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1 savings goals specified in paragraph (b-5) or (b-15) of 
2 this Section is possible both cost-effectively and within 
3 the expenditure limits in subsection (m), such savings 
4 goals shall not be reduced. Except as provided in 
5 subsection (m) of this Section, annual increases in 
6 cumulative persisting annual savings goals during the 
7 applicable 4-year plan period shall not be reduced to 
8 amounts that are less than the maximum amount of 
9 cumulative persisting annual savings that is forecast to 
10 be cost-effectively achievable during the 4-year plan 
11 period. The Commission shall review any proposed goal 
12 reduction as part of its review and approval of the 
13 utility's proposed plan.
14  (3) No later than March 1, 2025, each electric utility 
15 shall file a 4-year energy efficiency plan commencing on 
16 January 1, 2026 that is designed to achieve the cumulative 
17 persisting annual savings goals specified in paragraphs 
18 (9) through (12) of subsection (b-5) of this Section or in 
19 paragraphs (9) through (12) of subsection (b-15) of this 
20 Section, as applicable, through implementation of energy 
21 efficiency measures; however, the goals may be reduced if 
22 either (1) clear and convincing evidence demonstrates, 
23 through independent analysis, that the expenditure limits 
24 in subsection (m) of this Section preclude full 
25 achievement of the goals or (2) each of the following 
26 conditions are met: (A) the plan's analysis and forecasts 
 
 
SB2552- 55 -LRB103 31416 LNS 59082 b


1 of the utility's ability to acquire energy savings 
2 demonstrate by clear and convincing evidence and through 
3 independent analysis that achievement of such goals is not 
4 cost effective; and (B) the amount of energy savings 
5 achieved by the utility as determined by the independent 
6 evaluator for the most recent year for which savings have 
7 been evaluated preceding the plan filing was less than the 
8 average annual amount of savings required to achieve the 
9 goals for the applicable 4-year plan period. If there is 
10 not clear and convincing evidence that achieving the 
11 savings goals specified in paragraphs (b-5) or (b-15) of 
12 this Section is possible both cost-effectively and within 
13 the expenditure limits in subsection (m), such savings 
14 goals shall not be reduced. Except as provided in 
15 subsection (m) of this Section, annual increases in 
16 cumulative persisting annual savings goals during the 
17 applicable 4-year plan period shall not be reduced to 
18 amounts that are less than the maximum amount of 
19 cumulative persisting annual savings that is forecast to 
20 be cost-effectively achievable during the 4-year plan 
21 period. The Commission shall review any proposed goal 
22 reduction as part of its review and approval of the 
23 utility's proposed plan. 
24  (4) No later than March 1, 2029, and every 4 years 
25 thereafter, each electric utility shall file a 4-year 
26 energy efficiency plan commencing on January 1, 2030, and 
 
 
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1 every 4 years thereafter, respectively, that is designed 
2 to achieve the cumulative persisting annual savings goals 
3 established by the Illinois Commerce Commission pursuant 
4 to direction of subsections (b-5) and (b-15) of this 
5 Section, as applicable, through implementation of energy 
6 efficiency measures; however, the goals may be reduced if 
7 either (1) clear and convincing evidence and independent 
8 analysis demonstrates that the expenditure limits in 
9 subsection (m) of this Section preclude full achievement 
10 of the goals or (2) each of the following conditions are 
11 met: (A) the plan's analysis and forecasts of the 
12 utility's ability to acquire energy savings demonstrate by 
13 clear and convincing evidence and through independent 
14 analysis that achievement of such goals is not 
15 cost-effective; and (B) the amount of energy savings 
16 achieved by the utility as determined by the independent 
17 evaluator for the most recent year for which savings have 
18 been evaluated preceding the plan filing was less than the 
19 average annual amount of savings required to achieve the 
20 goals for the applicable 4-year plan period. If there is 
21 not clear and convincing evidence that achieving the 
22 savings goals specified in paragraphs (b-5) or (b-15) of 
23 this Section is possible both cost-effectively and within 
24 the expenditure limits in subsection (m), such savings 
25 goals shall not be reduced. Except as provided in 
26 subsection (m) of this Section, annual increases in 
 
 
SB2552- 57 -LRB103 31416 LNS 59082 b


1 cumulative persisting annual savings goals during the 
2 applicable 4-year plan period shall not be reduced to 
3 amounts that are less than the maximum amount of 
4 cumulative persisting annual savings that is forecast to 
5 be cost-effectively achievable during the 4-year plan 
6 period. The Commission shall review any proposed goal 
7 reduction as part of its review and approval of the 
8 utility's proposed plan.
9 Each utility's plan shall set forth the utility's 
10proposals to meet the energy efficiency standards identified 
11in subsection (b-5) or (b-15), as applicable and as such 
12standards may have been modified under this subsection (f), 
13taking into account the unique circumstances of the utility's 
14service territory. For those plans commencing on January 1, 
152018, the Commission shall seek public comment on the 
16utility's plan and shall issue an order approving or 
17disapproving each plan no later than 105 days after June 1, 
182017 (the effective date of Public Act 99-906). For those 
19plans commencing after December 31, 2021, the Commission shall 
20seek public comment on the utility's plan and shall issue an 
21order approving or disapproving each plan within 6 months 
22after its submission. If the Commission disapproves a plan, 
23the Commission shall, within 30 days, describe in detail the 
24reasons for the disapproval and describe a path by which the 
25utility may file a revised draft of the plan to address the 
26Commission's concerns satisfactorily. If the utility does not 
 
 
SB2552- 58 -LRB103 31416 LNS 59082 b


1refile with the Commission within 60 days, the utility shall 
2be subject to penalties at a rate of $100,000 per day until the 
3plan is filed. This process shall continue, and penalties 
4shall accrue, until the utility has successfully filed a 
5portfolio of energy efficiency and demand-response measures. 
6Penalties shall be deposited into the Energy Efficiency Trust 
7Fund. 
8 (g) In submitting proposed plans and funding levels under 
9subsection (f) of this Section to meet the savings goals 
10identified in subsection (b-5) or (b-15) of this Section, as 
11applicable, the utility shall:
12  (1) Demonstrate that its proposed energy efficiency 
13 measures will achieve the applicable requirements that are 
14 identified in subsection (b-5) or (b-15) of this Section, 
15 as modified by subsection (f) of this Section.
16  (2) (Blank).
17  (2.5) Demonstrate consideration of program options for 
18 (A) advancing new building codes, appliance standards, and 
19 municipal regulations governing existing and new building 
20 efficiency improvements and (B) supporting efforts to 
21 improve compliance with new building codes, appliance 
22 standards and municipal regulations, as potentially 
23 cost-effective means of acquiring energy savings to count 
24 toward savings goals. 
25  (3) Demonstrate that its overall portfolio of 
26 measures, not including low-income programs described in 
 
 
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1 subsection (c) of this Section, is cost-effective using 
2 the total resource cost test or complies with paragraphs 
3 (1) through (3) of subsection (f) of this Section and 
4 represents a diverse cross-section of opportunities for 
5 customers of all rate classes, other than those customers 
6 described in subsection (l) of this Section, to 
7 participate in the programs. Individual measures need not 
8 be cost effective.
9  (3.5) Demonstrate that the utility's plan integrates 
10 the delivery of energy efficiency programs with natural 
11 gas efficiency programs, programs promoting distributed 
12 solar, programs promoting demand response and other 
13 efforts to address bill payment issues, including, but not 
14 limited to, LIHEAP and the Percentage of Income Payment 
15 Plan, to the extent such integration is practical and has 
16 the potential to enhance customer engagement, minimize 
17 market confusion, or reduce administrative costs. 
18  (4) Present a third-party energy efficiency 
19 implementation program subject to the following 
20 requirements:
21   (A) beginning with the year commencing January 1, 
22 2019, electric utilities that serve more than 
23 3,000,000 retail customers in the State shall fund 
24 third-party energy efficiency programs in an amount 
25 that is no less than $25,000,000 per year, and 
26 electric utilities that serve less than 3,000,000 
 
 
SB2552- 60 -LRB103 31416 LNS 59082 b


1 retail customers but more than 500,000 retail 
2 customers in the State shall fund third-party energy 
3 efficiency programs in an amount that is no less than 
4 $8,350,000 per year;
5   (B) during 2018, the utility shall conduct a 
6 solicitation process for purposes of requesting 
7 proposals from third-party vendors for those 
8 third-party energy efficiency programs to be offered 
9 during one or more of the years commencing January 1, 
10 2019, January 1, 2020, and January 1, 2021; for those 
11 multi-year plans commencing on January 1, 2022 and 
12 January 1, 2026, the utility shall conduct a 
13 solicitation process during 2021 and 2025, 
14 respectively, for purposes of requesting proposals 
15 from third-party vendors for those third-party energy 
16 efficiency programs to be offered during one or more 
17 years of the respective multi-year plan period; for 
18 each solicitation process, the utility shall identify 
19 the sector, technology, or geographical area for which 
20 it is seeking requests for proposals; the solicitation 
21 process must be either for programs that fill gaps in 
22 the utility's program portfolio and for programs that 
23 target low-income customers, business sectors, 
24 building types, geographies, or other specific parts 
25 of its customer base with initiatives that would be 
26 more effective at reaching these customer segments 
 
 
SB2552- 61 -LRB103 31416 LNS 59082 b


1 than the utilities' programs filed in its energy 
2 efficiency plans;
3   (C) the utility shall propose the bidder 
4 qualifications, performance measurement process, and 
5 contract structure, which must include a performance 
6 payment mechanism and general terms and conditions; 
7 the proposed qualifications, process, and structure 
8 shall be subject to Commission approval; and
9   (D) the utility shall retain an independent third 
10 party to score the proposals received through the 
11 solicitation process described in this paragraph (4), 
12 rank them according to their cost per lifetime 
13 kilowatt-hours saved, and assemble the portfolio of 
14 third-party programs.
15  The electric utility shall recover all costs 
16 associated with Commission-approved, third-party 
17 administered programs regardless of the success of those 
18 programs. 
19  (4.5) Implement cost-effective demand-response 
20 measures to reduce peak demand by 0.1% over the prior year 
21 for eligible retail customers, as defined in Section 
22 16-111.5 of this Act, and for customers that elect hourly 
23 service from the utility pursuant to Section 16-107 of 
24 this Act, provided those customers have not been declared 
25 competitive. This requirement continues until December 31, 
26 2026. 
 
 
SB2552- 62 -LRB103 31416 LNS 59082 b


1  (5) Include a proposed or revised cost-recovery tariff 
2 mechanism, as provided for under subsection (d) of this 
3 Section, to fund the proposed energy efficiency and 
4 demand-response measures and to ensure the recovery of the 
5 prudently and reasonably incurred costs of 
6 Commission-approved programs.
7  (6) Provide for an annual independent evaluation of 
8 the performance of the cost-effectiveness of the utility's 
9 portfolio of measures, as well as a full review of the 
10 multi-year plan results of the broader net program impacts 
11 and, to the extent practical, for adjustment of the 
12 measures on a going-forward basis as a result of the 
13 evaluations. The resources dedicated to evaluation shall 
14 not exceed 3% of portfolio resources in any given year.
15  (7) For electric utilities that serve more than 
16 500,000 3,000,000 retail customers in the State:
17   (A) Through December 31, 2025, provide for an 
18 adjustment to the return on equity component of the 
19 utility's weighted average cost of capital calculated 
20 under subsection (d) of this Section:
21    (i) If the independent evaluator determines 
22 that the utility achieved a cumulative persisting 
23 annual savings that is less than the applicable 
24 annual incremental goal, then the return on equity 
25 component shall be reduced by a maximum of 200 
26 basis points in the event that the utility 
 
 
SB2552- 63 -LRB103 31416 LNS 59082 b


1 achieved no more than 75% of such goal. If the 
2 utility achieved more than 75% of the applicable 
3 annual incremental goal but less than 100% of such 
4 goal, then the return on equity component shall be 
5 reduced by 8 basis points for each percent by 
6 which the utility failed to achieve the goal.
7    (ii) If the independent evaluator determines 
8 that the utility achieved a cumulative persisting 
9 annual savings that is more than the applicable 
10 annual incremental goal, then the return on equity 
11 component shall be increased by a maximum of 200 
12 basis points in the event that the utility 
13 achieved at least 125% of such goal. If the 
14 utility achieved more than 100% of the applicable 
15 annual incremental goal but less than 125% of such 
16 goal, then the return on equity component shall be 
17 increased by 8 basis points for each percent by 
18 which the utility achieved above the goal. If the 
19 applicable annual incremental goal was reduced 
20 under paragraph paragraphs (1) or (2) of 
21 subsection (f) of this Section, then the following 
22 adjustments shall be made to the calculations 
23 described in this item (ii):
24     (aa) the calculation for determining 
25 achievement that is at least 125% of the 
26 applicable annual incremental goal shall use 
 
 
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1 the unreduced applicable annual incremental 
2 goal to set the value; and
3     (bb) the calculation for determining 
4 achievement that is less than 125% but more 
5 than 100% of the applicable annual incremental 
6 goal shall use the reduced applicable annual 
7 incremental goal to set the value for 100% 
8 achievement of the goal and shall use the 
9 unreduced goal to set the value for 125% 
10 achievement. The 8 basis point value shall 
11 also be modified, as necessary, so that the 
12 200 basis points are evenly apportioned among 
13 each percentage point value between 100% and 
14 125% achievement.
15   (B) For the period January 1, 2026 through 
16 December 31, 2029 and in all subsequent 4-year 
17 periods, provide for an adjustment to the return on 
18 equity component of the utility's weighted average 
19 cost of capital calculated under subsection (d) of 
20 this Section:
21    (i) If the independent evaluator determines 
22 that the utility achieved a cumulative persisting 
23 annual savings that is less than the applicable 
24 annual incremental goal, then the return on equity 
25 component shall be reduced by a maximum of 200 
26 basis points in the event that the utility 
 
 
SB2552- 65 -LRB103 31416 LNS 59082 b


1 achieved no more than 66% of such goal. If the 
2 utility achieved more than 66% of the applicable 
3 annual incremental goal but less than 100% of such 
4 goal, then the return on equity component shall be 
5 reduced by 6 basis points for each percent by 
6 which the utility failed to achieve the goal.
7    (ii) If the independent evaluator determines 
8 that the utility achieved a cumulative persisting 
9 annual savings that is more than the applicable 
10 annual incremental goal, then the return on equity 
11 component shall be increased by a maximum of 200 
12 basis points in the event that the utility 
13 achieved at least 134% of such goal. If the 
14 utility achieved more than 100% of the applicable 
15 annual incremental goal but less than 134% of such 
16 goal, then the return on equity component shall be 
17 increased by 6 basis points for each percent by 
18 which the utility achieved above the goal. If the 
19 applicable annual incremental goal was reduced 
20 under paragraph (3) of subsection (f) of this 
21 Section, then the following adjustments shall be 
22 made to the calculations described in this item 
23 (ii):
24     (aa) the calculation for determining 
25 achievement that is at least 134% of the 
26 applicable annual incremental goal shall use 
 
 
SB2552- 66 -LRB103 31416 LNS 59082 b


1 the unreduced applicable annual incremental 
2 goal to set the value; and
3     (bb) the calculation for determining 
4 achievement that is less than 134% but more 
5 than 100% of the applicable annual incremental 
6 goal shall use the reduced applicable annual 
7 incremental goal to set the value for 100% 
8 achievement of the goal and shall use the 
9 unreduced goal to set the value for 134% 
10 achievement. The 6 basis point value shall 
11 also be modified, as necessary, so that the 
12 200 basis points are evenly apportioned among 
13 each percentage point value between 100% and 
14 134% achievement. 
15   (C) Notwithstanding the provisions of 
16 subparagraphs (A) and (B) of this paragraph (7), if 
17 the applicable annual incremental goal for an electric 
18 utility is ever less than 0.6% of deemed average 
19 weather normalized sales of electric power and energy 
20 during calendar years 2014, 2015, and 2016, an 
21 adjustment to the return on equity component of the 
22 utility's weighted average cost of capital calculated 
23 under subsection (d) of this Section shall be made as 
24 follows:
25    (i) If the independent evaluator determines 
26 that the utility achieved a cumulative persisting 
 
 
SB2552- 67 -LRB103 31416 LNS 59082 b


1 annual savings that is less than would have been 
2 achieved had the applicable annual incremental 
3 goal been achieved, then the return on equity 
4 component shall be reduced by a maximum of 200 
5 basis points if the utility achieved no more than 
6 75% of its applicable annual total savings 
7 requirement as defined in paragraph (7.5) of this 
8 subsection. If the utility achieved more than 75% 
9 of the applicable annual total savings requirement 
10 but less than 100% of such goal, then the return on 
11 equity component shall be reduced by 8 basis 
12 points for each percent by which the utility 
13 failed to achieve the goal.
14    (ii) If the independent evaluator determines 
15 that the utility achieved a cumulative persisting 
16 annual savings that is more than would have been 
17 achieved had the applicable annual incremental 
18 goal been achieved, then the return on equity 
19 component shall be increased by a maximum of 200 
20 basis points if the utility achieved at least 125% 
21 of its applicable annual total savings 
22 requirement. If the utility achieved more than 
23 100% of the applicable annual total savings 
24 requirement but less than 125% of such goal, then 
25 the return on equity component shall be increased 
26 by 8 basis points for each percent by which the 
 
 
SB2552- 68 -LRB103 31416 LNS 59082 b


1 utility achieved above the applicable annual total 
2 savings requirement. If the applicable annual 
3 incremental goal was reduced under paragraph (1) 
4 or (2) of subsection (f) of this Section, then the 
5 following adjustments shall be made to the 
6 calculations described in this item (ii):
7     (aa) the calculation for determining 
8 achievement that is at least 125% of the 
9 applicable annual total savings requirement 
10 shall use the unreduced applicable annual 
11 incremental goal to set the value; and
12     (bb) the calculation for determining 
13 achievement that is less than 125% but more 
14 than 100% of the applicable annual total 
15 savings requirement shall use the reduced 
16 applicable annual incremental goal to set the 
17 value for 100% achievement of the goal and 
18 shall use the unreduced goal to set the value 
19 for 125% achievement. The 8 basis point value 
20 shall also be modified, as necessary, so that 
21 the 200 basis points are evenly apportioned 
22 among each percentage point value between 100% 
23 and 125% achievement. 
24  (7.5) For purposes of this Section, the term 
25 "applicable
annual incremental goal" means the difference 
26 between the
cumulative persisting annual savings goal for 
 
 
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1 the calendar
year that is the subject of the independent 
2 evaluator's
determination and the cumulative persisting 
3 annual savings
goal for the immediately preceding calendar 
4 year, as such
goals are defined in subsections (b-5) and 
5 (b-15) of this
Section and as these goals may have been 
6 modified as
provided for under subsection (b-20) and 
7 paragraphs (1)
through (3) of subsection (f) of this 
8 Section. Under
subsections (b), (b-5), (b-10), and (b-15) 
9 of this Section,
a utility must first replace energy 
10 savings from measures
that have expired before any 
11 progress towards achievement of its
applicable annual 
12 incremental goal may be counted. Savings may expire 
13 because measures installed in previous years have reached 
14 the end of their lives, because measures installed in 
15 previous years are producing lower savings in the current 
16 year than in the previous year, or for other reasons 
17 identified by independent evaluators.
Notwithstanding 
18 anything else set forth in this Section,
the difference 
19 between the actual annual incremental
savings achieved in 
20 any given year, including the
replacement of energy 
21 savings that have
expired, and the applicable annual 
22 incremental goal shall
not affect adjustments to the 
23 return on equity for
subsequent calendar years under this 
24 subsection (g). 
25  In this Section, "applicable annual total savings 
26 requirement" means the total amount of new annual savings 
 
 
SB2552- 70 -LRB103 31416 LNS 59082 b


1 that the utility must achieve in any given year to achieve 
2 the applicable annual incremental goal. This is equal to 
3 the applicable annual incremental goal plus the total new 
4 annual savings that are required to replace savings that 
5 expired in or at the end of the previous year. 
6  (8) (Blank). For electric utilities that serve less 
7 than 3,000,000 retail customers but more than 500,000 
8 retail customers in the State:
9   (A) Through December 31, 2025, the applicable 
10 annual incremental goal shall be compared to the 
11 annual incremental savings as determined by the 
12 independent evaluator.
13    (i) The return on equity component shall be 
14 reduced by 8 basis points for each percent by 
15 which the utility did not achieve 84.4% of the 
16 applicable annual incremental goal.
17    (ii) The return on equity component shall be 
18 increased by 8 basis points for each percent by 
19 which the utility exceeded 100% of the applicable 
20 annual incremental goal.
21    (iii) The return on equity component shall not 
22 be increased or decreased if the annual 
23 incremental savings as determined by the 
24 independent evaluator is greater than 84.4% of the 
25 applicable annual incremental goal and less than 
26 100% of the applicable annual incremental goal.
 
 
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1    (iv) The return on equity component shall not 
2 be increased or decreased by an amount greater 
3 than 200 basis points pursuant to this 
4 subparagraph (A).
5   (B) For the period of January 1, 2026 through 
6 December 31, 2029 and in all subsequent 4-year 
7 periods, the applicable annual incremental goal shall 
8 be compared to the annual incremental savings as 
9 determined by the independent evaluator.
10    (i) The return on equity component shall be 
11 reduced by 6 basis points for each percent by 
12 which the utility did not achieve 100% of the 
13 applicable annual incremental goal.
14    (ii) The return on equity component shall be 
15 increased by 6 basis points for each percent by 
16 which the utility exceeded 100% of the applicable 
17 annual incremental goal.
18    (iii) The return on equity component shall not 
19 be increased or decreased by an amount greater 
20 than 200 basis points pursuant to this 
21 subparagraph (B).
22   (C) Notwithstanding provisions in subparagraphs 
23 (A) and (B) of paragraph (7) of this subsection, if the 
24 applicable annual incremental goal for an electric 
25 utility is ever less than 0.6% of deemed average 
26 weather normalized sales of electric power and energy 
 
 
SB2552- 72 -LRB103 31416 LNS 59082 b


1 during calendar years 2014, 2015 and 2016, an 
2 adjustment to the return on equity component of the 
3 utility's weighted average cost of capital calculated 
4 under subsection (d) of this Section shall be made as 
5 follows:
6    (i) The return on equity component shall be 
7 reduced by 8 basis points for each percent by 
8 which the utility did not achieve 100% of the 
9 applicable annual total savings requirement.
10    (ii) The return on equity component shall be 
11 increased by 8 basis points for each percent by 
12 which the utility exceeded 100% of the applicable 
13 annual total savings requirement.
14    (iii) The return on equity component shall not 
15 be increased or decreased by an amount greater 
16 than 200 basis points pursuant to this 
17 subparagraph (C). 
18   (D) If the applicable annual incremental goal was 
19 reduced under paragraph (1), (2), (3), or (4) of 
20 subsection (f) of this Section, then the following 
21 adjustments shall be made to the calculations 
22 described in subparagraphs (A), (B), and (C) of this 
23 paragraph (8):
24    (i) The calculation for determining 
25 achievement that is at least 125% or 134%, as 
26 applicable, of the applicable annual incremental 
 
 
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1 goal or the applicable annual total savings 
2 requirement, as applicable, shall use the 
3 unreduced applicable annual incremental goal to 
4 set the value.
5    (ii) For the period through December 31, 2025, 
6 the calculation for determining achievement that 
7 is less than 125% but more than 100% of the 
8 applicable annual incremental goal or the 
9 applicable annual total savings requirement, as 
10 applicable, shall use the reduced applicable 
11 annual incremental goal to set the value for 100% 
12 achievement of the goal and shall use the 
13 unreduced goal to set the value for 125% 
14 achievement. The 8 basis point value shall also be 
15 modified, as necessary, so that the 200 basis 
16 points are evenly apportioned among each 
17 percentage point value between 100% and 125% 
18 achievement.
19    (iii) For the period of January 1, 2026 
20 through December 31, 2029 and all subsequent 
21 4-year periods, the calculation for determining 
22 achievement that is less than 125% or 134%, as 
23 applicable, but more than 100% of the applicable 
24 annual incremental goal or the applicable annual 
25 total savings requirement, as applicable, shall 
26 use the reduced applicable annual incremental goal 
 
 
SB2552- 74 -LRB103 31416 LNS 59082 b


1 to set the value for 100% achievement of the goal 
2 and shall use the unreduced goal to set the value 
3 for 125% achievement. The 6 basis-point value or 8 
4 basis-point value, as applicable, shall also be 
5 modified, as necessary, so that the 200 basis 
6 points are evenly apportioned among each 
7 percentage point value between 100% and 125% or 
8 between 100% and 134% achievement, as applicable.
9  (9) The utility shall submit the energy savings data 
10 to the independent evaluator no later than 30 days after 
11 the close of the plan year. The independent evaluator 
12 shall determine the cumulative persisting annual savings 
13 for a given plan year, as well as an estimate of job 
14 impacts and other macroeconomic impacts of the efficiency 
15 programs for that year, no later than 120 days after the 
16 close of the plan year. The utility shall submit an 
17 informational filing to the Commission no later than 160 
18 days after the close of the plan year that attaches the 
19 independent evaluator's final report identifying the 
20 cumulative persisting annual savings for the year and 
21 calculates, under paragraph (7) or (8) of this subsection 
22 (g), as applicable, any resulting change to the utility's 
23 return on equity component of the weighted average cost of 
24 capital applicable to the next plan year beginning with 
25 the January monthly billing period and extending through 
26 the December monthly billing period. However, if the 
 
 
SB2552- 75 -LRB103 31416 LNS 59082 b


1 utility recovers the costs incurred under this Section 
2 under paragraphs (2) and (3) of subsection (d) of this 
3 Section, then the utility shall not be required to submit 
4 such informational filing, and shall instead submit the 
5 information that would otherwise be included in the 
6 informational filing as part of its filing under paragraph 
7 (3) of such subsection (d) that is due on or before June 1 
8 of each year.
9  For those utilities that must submit the informational 
10 filing, the Commission may, on its own motion or by 
11 petition, initiate an investigation of such filing, 
12 provided, however, that the utility's proposed return on 
13 equity calculation shall be deemed the final, approved 
14 calculation on December 15 of the year in which it is filed 
15 unless the Commission enters an order on or before 
16 December 15, after notice and hearing, that modifies such 
17 calculation consistent with this Section.
18  The adjustments to the return on equity component 
19 described in paragraph paragraphs (7) and (8) of this 
20 subsection (g) shall be applied as described in such 
21 paragraphs through a separate tariff mechanism, which 
22 shall be filed by the utility under subsections (f) and 
23 (g) of this Section. 
24  (9.5) The utility must demonstrate how it will ensure 
25 that program implementation contractors and energy 
26 efficiency installation vendors will promote workforce 
 
 
SB2552- 76 -LRB103 31416 LNS 59082 b


1 equity and quality jobs.
2  (9.6) Utilities shall collect data necessary to ensure 
3 compliance with paragraph (9.5) no less than quarterly and 
4 shall communicate progress toward compliance with 
5 paragraph (9.5) to program implementation contractors and 
6 energy efficiency installation vendors no less than 
7 quarterly. Utilities shall work with relevant vendors, 
8 providing education, training, and other resources needed 
9 to ensure compliance and, where necessary, adjusting or 
10 terminating work with vendors that cannot assist with 
11 compliance.
12  (10) Utilities required to implement efficiency 
13 programs under subsections (b-5) and (b-10) shall report 
14 annually to the Illinois Commerce Commission and the 
15 General Assembly on how hiring, contracting, job training, 
16 and other practices related to its energy efficiency 
17 programs enhance the diversity of vendors working on such 
18 programs. These reports must include data on vendor and 
19 employee diversity, including data on the implementation 
20 of paragraphs (9.5) and (9.6). If the utility is not 
21 meeting the requirements of paragraphs (9.5) and (9.6), 
22 the utility shall submit a plan to adjust their activities 
23 so that they meet the requirements of paragraphs (9.5) and 
24 (9.6) within the following year.
25 (h) No more than 4% of energy efficiency and 
26demand-response program revenue may be allocated for research, 
 
 
SB2552- 77 -LRB103 31416 LNS 59082 b


1development, or pilot deployment of new equipment or measures. 
2Electric utilities shall work with interested stakeholders to 
3formulate a plan for how these funds should be spent, 
4incorporate statewide approaches for these allocations, and 
5file a 4-year plan that demonstrates that collaboration. If a 
6utility files a request for modified annual energy savings 
7goals with the Commission, then a utility shall forgo spending 
8portfolio dollars on research and development proposals. 

9 (i) When practicable, electric utilities shall incorporate 
10advanced metering infrastructure data into the planning, 
11implementation, and evaluation of energy efficiency measures 
12and programs, subject to the data privacy and confidentiality 
13protections of applicable law.
14 (j) The independent evaluator shall follow the guidelines 
15and use the savings set forth in Commission-approved energy 
16efficiency policy manuals and technical reference manuals, as 
17each may be updated from time to time. Until such time as 
18measure life values for energy efficiency measures implemented 
19for low-income households under subsection (c) of this Section 
20are incorporated into such Commission-approved manuals, the 
21low-income measures shall have the same measure life values 
22that are established for same measures implemented in 
23households that are not low-income households.
24 (k) Notwithstanding any provision of law to the contrary, 
25an electric utility subject to the requirements of this 
26Section may file a tariff cancelling an automatic adjustment 
 
 
SB2552- 78 -LRB103 31416 LNS 59082 b


1clause tariff in effect under this Section or Section 8-103, 
2which shall take effect no later than one business day after 
3the date such tariff is filed. Thereafter, the utility shall 
4be authorized to defer and recover its expenditures incurred 
5under this Section through a new tariff authorized under 
6subsection (d) of this Section or in the utility's next rate 
7case under Article IX or Section 16-108.5 of this Act, with 
8interest at an annual rate equal to the utility's weighted 
9average cost of capital as approved by the Commission in such 
10case. If the utility elects to file a new tariff under 
11subsection (d) of this Section, the utility may file the 
12tariff within 10 days after June 1, 2017 (the effective date of 
13Public Act 99-906), and the cost inputs to such tariff shall be 
14based on the projected costs to be incurred by the utility 
15during the calendar year in which the new tariff is filed and 
16that were not recovered under the tariff that was cancelled as 
17provided for in this subsection. Such costs shall include 
18those incurred or to be incurred by the utility under its 
19multi-year plan approved under subsections (f) and (g) of this 
20Section, including, but not limited to, projected capital 
21investment costs and projected regulatory asset balances with 
22correspondingly updated depreciation and amortization reserves 
23and expense. The Commission shall, after notice and hearing, 
24approve, or approve with modification, such tariff and cost 
25inputs no later than 75 days after the utility filed the 
26tariff, provided that such approval, or approval with 
 
 
SB2552- 79 -LRB103 31416 LNS 59082 b


1modification, shall be consistent with the provisions of this 
2Section to the extent they do not conflict with this 
3subsection (k). The tariff approved by the Commission shall 
4take effect no later than 5 days after the Commission enters 
5its order approving the tariff.
6 No later than 60 days after the effective date of the 
7tariff cancelling the utility's automatic adjustment clause 
8tariff, the utility shall file a reconciliation that 
9reconciles the moneys collected under its automatic adjustment 
10clause tariff with the costs incurred during the period 
11beginning June 1, 2016 and ending on the date that the electric 
12utility's automatic adjustment clause tariff was cancelled. In 
13the event the reconciliation reflects an under-collection, the 
14utility shall recover the costs as specified in this 
15subsection (k). If the reconciliation reflects an 
16over-collection, the utility shall apply the amount of such 
17over-collection as a one-time credit to retail customers' 
18bills.
19 (l) (Blank). For the calendar years covered by a 
20multi-year plan
commencing after December 31, 2017, 
21subsections (a) through
(j) of this Section do not apply to 
22eligible large private
energy customers that have chosen to 
23opt out of multi-year
plans consistent with this subsection

24(1).
25  (1) For purposes of this subsection (l), "eligible

26 large private energy customer" means any retail
customers, 
 
 
SB2552- 80 -LRB103 31416 LNS 59082 b


1 except for federal, State, municipal, and other
public 
2 customers, of an electric utility that serves more
than 
3 3,000,000 retail customers, except for federal,
State, 
4 municipal and other public customers, in the State
and 
5 whose total highest 30 minute demand was more than
10,000 
6 kilowatts, or any retail customers of an electric
utility 
7 that serves less than 3,000,000 retail customers
but more 
8 than 500,000 retail customers in the State and
whose total 
9 highest 15 minute demand was more than 10,000
kilowatts. 
10 For purposes of this subsection (l), "retail
customer" has 
11 the meaning set forth in Section 16-102 of
this Act. 
12 However, for a business entity with multiple sites located 
13 in the State, where at least one of those sites qualifies 
14 as an eligible large private energy customer, then any of 
15 that business entity's sites, properly identified on a 
16 form for notice, shall be considered eligible large 
17 private energy customers for the purposes of this 
18 subsection (l). A determination of whether this subsection 
19 is
applicable to a customer shall be made for each 
20 multi-year
plan beginning after December 31, 2017. The 
21 criteria for
determining whether this subsection (l) is 
22 applicable to a
retail customer shall be based on the 12 
23 consecutive
billing periods prior to the start of the 
24 first year of
each such multi-year plan.
25  (2) Within 45 days after the effective date of this 
26 amendatory Act of the 102nd General Assembly, the 
 
 
SB2552- 81 -LRB103 31416 LNS 59082 b


1 Commission shall prescribe the form for notice
required 
2 for opting out of energy efficiency programs. The
notice 
3 must be submitted to the retail electric utility 12 months

4 before the next energy efficiency planning cycle. However, 
5 within 120 days after the Commission's initial issuance of 
6 the form for notice, eligible large private energy 
7 customers may submit a form for notice to an electric 
8 utility. The form for notice for opting out of energy 
9 efficiency programs shall
include all of the following:
10   (A) a statement indicating that the customer has

11 elected to opt out;
12   (B) the account numbers for the customer accounts 
13 to
which the opt out shall apply;
14   (C) the mailing address associated with the

15 customer accounts identified under subparagraph (B);
16   (D) an American Society of Heating, Refrigerating,

17 and Air-Conditioning Engineers (ASHRAE) level 2 or

18 higher audit report conducted by an independent 
19 third-party expert identifying cost-effective energy

20 efficiency project opportunities that could be

21 invested in over the next 10 years. A retail customer 
22 with specialized processes may utilize a self-audit 
23 process in lieu of the ASHRAE audit;
24   (E) a description of the customer's plans to

25 reallocate the funds toward internal energy efficiency

26 efforts identified in the subparagraph (D) report,

 
 
SB2552- 82 -LRB103 31416 LNS 59082 b


1 including, but not limited to: (i) strategic energy

2 management or other programs, including descriptions

3 of targeted buildings, equipment and operations; (ii)

4 eligible energy efficiency measures; and (iii)

5 expected energy savings, itemized by technology. If 
6 the subparagraph (D) audit report identifies that the 
7 customer currently utilizes the best available energy 
8 efficient technology, equipment, programs, and 
9 operations, the customer may provide a statement that 
10 more efficient technology, equipment, programs, and 
11 operations are not reasonably available as a means of 
12 satisfying this subparagraph (E); and
13   (F) the effective date of the opt out, which will

14 be the next January 1 following notice of the opt out.
15  (3) Upon receipt of a properly and timely noticed

16 request for opt out submitted by an eligible large private

17 energy customer, the retail electric utility shall grant 
18 the
request, file the request with the Commission and,

19 beginning January 1 of the following year, the opted out

20 customer shall no longer be assessed the costs of the plan

21 and shall be prohibited from participating in that
4-year 
22 plan cycle to give the retail utility the
certainty to 
23 design program plan proposals.
24  (4) Upon a customer's election to opt out under

25 paragraphs (1) and (2) of this subsection (l) and

26 commencing on the effective date of said opt out, the

 
 
SB2552- 83 -LRB103 31416 LNS 59082 b


1 account properly identified in the customer's notice under

2 paragraph (2) shall not be subject to any cost recovery

3 and shall not be eligible to participate in, or directly

4 benefit from, compliance with energy efficiency cumulative

5 persisting savings requirements under subsections (a)

6 through (j).
7  (5) A utility's cumulative persisting annual savings

8 targets will exclude any opted out load.
9  (6) The request to opt out is only valid for the

10 requested plan cycle. An eligible large private energy

11 customer must also request to opt out for future energy

12 plan cycles, otherwise the customer will be included in

13 the future energy plan cycle. 
14 (m) Notwithstanding the requirements of this Section, as 
15part of a proceeding to approve a multi-year plan under 
16subsections (f) and (g) of this Section if the multi-year plan 
17has been designed to maximize savings, but does not meet the 
18cost cap limitations of this Section, the Commission shall 
19reduce the amount of energy efficiency measures implemented 
20for any single year, and whose costs are recovered under 
21subsection (d) of this Section, by an amount necessary to 
22limit the estimated average net increase due to the cost of the 
23measures to no more than
24  (1) 3.5% for each of the 4 years beginning January 1, 
25 2018,
26  (2) (blank),
 
 
SB2552- 84 -LRB103 31416 LNS 59082 b


1  (3) 4% for each of the 4 years beginning January 1, 
2 2022,
3  (4) 4.25% for the 4 years beginning January 1, 2026, 
4 and
5  (5) 4.25% plus an increase sufficient to account for 
6 the rate of inflation between January 1, 2026 and January 
7 1 of the first year of each subsequent 4-year plan cycle, 
8of the average amount paid per kilowatthour by residential 
9eligible retail customers during calendar year 2015. An 
10electric utility may plan to spend up to 10% more in any year 
11during an applicable multi-year plan period to 
12cost-effectively achieve additional savings so long as the 
13average over the applicable multi-year plan period does not 
14exceed the percentages defined in items (1) through (5). To 
15determine the total amount that may be spent by an electric 
16utility in any single year, the applicable percentage of the 
17average amount paid per kilowatthour shall be multiplied by 
18the total amount of energy delivered by such electric utility 
19in the calendar year 2015, adjusted to reflect the proportion 
20of the utility's load attributable to customers that have 
21opted out of subsections (a) through (j) of this Section under 
22subsection (l) of this Section. For purposes of this 
23subsection (m), the amount paid per kilowatthour includes,

24without limitation, estimated amounts paid for supply,

25transmission, distribution, surcharges, and add-on taxes. For 
26purposes of this Section, "eligible retail customers" shall 
 
 
SB2552- 85 -LRB103 31416 LNS 59082 b


1have the meaning set forth in Section 16-111.5 of this Act. 
2Once the Commission has approved a plan under subsections (f) 
3and (g) of this Section, no subsequent rate impact 
4determinations shall be made.
5 (n) A utility shall take advantage of the efficiencies 
6available through existing Illinois Home Weatherization 
7Assistance Program infrastructure and services, such as 
8enrollment, marketing, quality assurance and implementation, 
9which can reduce the need for similar services at a lower cost 
10than utility-only programs, subject to capacity constraints at 
11community action agencies, for both single-family and 
12multifamily weatherization services, to the extent Illinois 
13Home Weatherization Assistance Program community action 
14agencies provide multifamily services. A utility's plan shall 
15demonstrate that in formulating annual weatherization budgets, 
16it has sought input and coordination with community action 
17agencies regarding agencies' capacity to expand and maximize 
18Illinois Home Weatherization Assistance Program delivery using 
19the ratepayer dollars collected under this Section. 

20(Source: P.A. 101-81, eff. 7-12-19; 102-662, eff. 9-15-21; 
21revised 2-28-22.)

22 (220 ILCS 5/16-107.8 new)
23 Sec. 16-107.8. Residential time-of-use pricing.
24 (a) The General Assembly finds that time-of-use rates and 
25pricing plans can lower energy costs for consumers and reduce 
 
 
SB2552- 86 -LRB103 31416 LNS 59082 b


1grid costs as well as help the State achieve its energy policy 
2goals by improving load shape, encouraging energy 
3conservation, and shifting usage away from periods where 
4fossil fuels are used to meet peak demand. Further, by 
5providing consumers information relating the costs of service 
6to the time of energy usage, time-of-use rates can help 
7consumers reduce their energy bills by using electricity when 
8it is less costly. Time-of-use rates can help allocate 
9electricity system costs more accurately and thus equitably to 
10those who cause costs. Such rates can reduce the need for 
11ramping resources and increase the grid's ability to 
12cost-effectively integrate greater quantities of variable 
13renewable energy and distributed energy resources.
14 (b) An electric utility that has a tariff approved under 
15subsection (d) of Section 16-108.18 within one year of this 
16amendatory Act of the 103rd General Assembly shall also offer 
17at least one market-based, time-of-use rate for eligible 
18retail customers that choose to take power and energy supply 
19service from the utility. If the utility has a pending request 
20for approval of a Multi-Year Integrated Grid Plan, the utility 
21shall update its filing in that docket to reflect the likely 
22impacts of the time-of-use rate offering. The utility shall 
23file its time-of-use rate tariff no later than 120 days after 
24the effective date of this amendatory Act of the 103rd General 
25Assembly, and each utility subject to this requirement shall 
26implement the requirements of this subsection by filing a 
 
 
SB2552- 87 -LRB103 31416 LNS 59082 b


1tariff with the Commission. The tariff or tariffs shall be 
2subject to the following provisions:
3  (1) If more than one tariff is proposed, at least one 
4 tariff shall include at least 3 time blocks: a peak time 
5 block, defined as 2 p.m. to 7 p.m. on nonholiday weekdays 
6 or the 5 consecutive hours best reflecting the highest 
7 system peak demands; an off-peak time block, defined as 10 
8 a.m. to 2 p.m. and 7 p.m. to 10 p.m. on nonholiday weekdays 
9 or the 7 total hours occurring in some combination before 
10 and after the peak period, which reflect the next highest 
11 system peak demands; and a super-off-peak time block, 
12 defined as all other hours and including weekend days.
13  (2) This tariff shall strive to achieve price ratios 
14 between the blocks as follows: the super-off-peak time 
15 block price shall be no less than zero but no greater than 
16 one-half of the price of the off-peak time block price, 
17 and the off-peak time block price shall be no greater than 
18 one-half of the price of the peak time block price.
19  (3) The time-of-use rate shall include the costs of 
20 electric capacity, costs of transmission services, and 
21 charges for network integration transmission service, 
22 transmission enhancement, and locational reliability, as 
23 these terms are defined in the PJM Interconnection LLC 
24 Open Access Transmission Tariff and manuals on January 1, 
25 2019, within the prices for each time block and seasonal 
26 block in which the associated costs generally are 
 
 
SB2552- 88 -LRB103 31416 LNS 59082 b


1 incurred. If the Open Access Transmission Tariff or 
2 manuals subsequently renames those terms, the services 
3 reflected under those terms shall continue to be included 
4 in the time-of-use rate described in this paragraph.
5  (4) Adjustments to the charges set by the tariff may 
6 be made on a semi-annual basis, as follows: each May and 
7 November, the utility shall submit to the Commission, 
8 through an informational filing, its updated charges, and 
9 such charges shall take effect beginning with the June 
10 monthly billing period and December monthly billing 
11 period, respectively.
12  (5) The tariff shall include a purchased energy 
13 adjustment to fully recover the supply costs for the 
14 customers taking service under this tariff.
15 As used in this subsection, "eligible retail customers" 
16includes, but is not limited to, customers participating in 
17net electricity metering under the terms of Section 16-107.5.
18 (c) The Commission shall, after notice and hearing, 
19approve the tariff or tariffs with modifications the 
20Commission finds necessary to improve the program design, 
21customer participation in the program, or coordination with 
22existing utility pricing programs, energy efficiency programs, 
23demand response programs, and any other programs supporting 
24State energy policy goals and the integration of distributed 
25energy resources. The Commission shall also consider how the 
26proposed time-of-use rate design reflects the system costs and 
 
 
SB2552- 89 -LRB103 31416 LNS 59082 b


1usage patterns of the utility. A proceeding under this 
2subsection may not exceed 120 days in length.
3 (d) If the Commission issues an order pursuant to this 
4subsection, the affected electric utility shall contract with 
5an entity not affiliated with the electric utility to serve as 
6a program administrator to develop and implement a program to 
7provide consumer outreach, enrollment, and education 
8concerning time-of-use pricing and to establish and administer 
9an information system and technical and other customer 
10assistance that is necessary to enable customers to manage 
11electricity use. The program administrator: (i) shall be 
12selected and compensated by the electric utility, subject to 
13Commission approval; (ii) shall have demonstrated technical 
14and managerial competence in the development and 
15administration of demand management programs; and (iii) may 
16develop and implement risk management, energy efficiency, and 
17other services related to energy use management for which the 
18program administrator shall be compensated by participants in 
19the program receiving such services. The electric utility 
20shall provide the program administrator with all information 
21and assistance necessary to perform the program 
22administrator's duties, including, but not limited to, 
23customer, account, and energy use data. The electric utility 
24shall permit the program administrator to include inserts in 
25residential customer bills 2 times per year to assist with 
26customer outreach and enrollment. The program administrator 
 
 
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1shall submit an annual report to the electric utility no later 
2than April 1 of each year describing the operation and results 
3of the program, including information concerning the number 
4and types of customers using the program, changes in 
5customers' energy use patterns, an assessment of the value of 
6the program to both participants and nonparticipants, and 
7recommendations concerning modification of the program and the 
8tariff or tariffs filed under this Section. This report shall 
9be filed by the electric utility with the Commission within 30 
10days after receipt and shall be available to the public on the 
11Commission's website.
12 (e) Once the tariff or tariffs has been in effect for 12 
13months, the Commission may, upon complaint, petition, or its 
14own initiative, open a proceeding to investigate whether 
15changes or modifications to the tariff or tariffs, program 
16administration and any other program design element is 
17necessary to achieve the goals described in subsection (a) and 
18to shifting usage away from periods where fossil fuels are 
19used to meet peak demand and realign usage to periods when 
20renewable generation is available. Such a proceeding may not 
21last more than 180 days from the date upon which the 
22investigation is opened by Commission order. Thereafter, the 
23Commission may, upon complaint, petition, or its own 
24initiative, open a proceeding to investigate changes or 
25modifications to the tariff or tariffs at any time the 
26Commission deems reasonable in order to achieve these 
 
 
SB2552- 91 -LRB103 31416 LNS 59082 b


1objectives.
2 (f) An electric utility shall be entitled to recover 
3reasonable costs incurred in complying with this Section, if 
4the recovery of the costs is fairly apportioned among its 
5residential customers.
6 (g) The electric utility's tariff or tariffs filed 
7pursuant to this Section shall be subject to the provisions of 
8Article IX of this Act insofar as they do not conflict with 
9this Section.
10 (h) This Section does not apply to any electric utility 
11providing service to 100,000 or fewer customers.

12 (220 ILCS 5/16-111.5)
13 Sec. 16-111.5. Provisions relating to procurement.
14 (a) An electric utility that on December 31, 2005 served 
15at least 100,000 customers in Illinois shall procure power and 
16energy for its eligible retail customers in accordance with 
17the applicable provisions set forth in Section 1-75 of the 
18Illinois Power Agency Act and this Section. Beginning with the 
19delivery year commencing on June 1, 2017, such electric 
20utility shall also procure zero emission credits from zero 
21emission facilities in accordance with the applicable 
22provisions set forth in Section 1-75 of the Illinois Power 
23Agency Act, and, for years beginning on or after June 1, 2017, 
24the utility shall procure renewable energy resources in 
25accordance with the applicable provisions set forth in Section 
 
 
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11-75 of the Illinois Power Agency Act and this Section. 
2Beginning with the delivery year commencing on June 1, 2022, 
3an electric utility serving over 3,000,000 customers shall 
4also procure carbon mitigation credits from carbon-free energy 
5resources in accordance with the applicable provisions set 
6forth in Section 1-75 of the Illinois Power Agency Act and this 
7Section. A small multi-jurisdictional electric utility that on 
8December 31, 2005 served less than 100,000 customers in 
9Illinois may elect to procure power and energy for all or a 
10portion of its eligible Illinois retail customers in 
11accordance with the applicable provisions set forth in this 
12Section and Section 1-75 of the Illinois Power Agency Act. 
13This Section shall not apply to a small multi-jurisdictional 
14utility until such time as a small multi-jurisdictional 
15utility requests the Illinois Power Agency to prepare a 
16procurement plan for its eligible retail customers. "Eligible 
17retail customers" for the purposes of this Section means those 
18retail customers that purchase power and energy from the 
19electric utility under fixed-price bundled service tariffs, 
20other than those retail customers whose service is declared or 
21deemed competitive under Section 16-113 and those other 
22customer groups specified in this Section, including 
23self-generating customers, customers electing hourly pricing, 
24or those customers who are otherwise ineligible for 
25fixed-price bundled tariff service. For those customers that 
26are excluded from the procurement plan's electric supply 
 
 
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1service requirements, and the utility shall procure any supply 
2requirements, including capacity, ancillary services, and 
3hourly priced energy, in the applicable markets as needed to 
4serve those customers, provided that the utility may include 
5in its procurement plan load requirements for the load that is 
6associated with those retail customers whose service has been 
7declared or deemed competitive pursuant to Section 16-113 of 
8this Act to the extent that those customers are purchasing 
9power and energy during one of the transition periods 
10identified in subsection (b) of Section 16-113 of this Act. 
11 (b) A procurement plan shall be prepared for each electric 
12utility consistent with the applicable requirements of the 
13Illinois Power Agency Act and this Section. For purposes of 
14this Section, Illinois electric utilities that are affiliated 
15by virtue of a common parent company are considered to be a 
16single electric utility. Small multi-jurisdictional utilities 
17may request a procurement plan for a portion of or all of its 
18Illinois load. Each procurement plan shall analyze the 
19projected balance of supply and demand for those retail 
20customers to be included in the plan's electric supply service 
21requirements over a 5-year period, with the first planning 
22year beginning on June 1 of the year following the year in 
23which the plan is filed. The plan shall specifically identify 
24the wholesale products to be procured following plan approval, 
25and shall follow all the requirements set forth in the Public 
26Utilities Act and all applicable State and federal laws, 
 
 
SB2552- 94 -LRB103 31416 LNS 59082 b


1statutes, rules, or regulations, as well as Commission orders. 
2Nothing in this Section precludes consideration of contracts 
3longer than 5 years and related forecast data. Unless 
4specified otherwise in this Section, in the procurement plan 
5or in the implementing tariff, any procurement occurring in 
6accordance with this plan shall be competitively bid through a 
7request for proposals process. Approval and implementation of 
8the procurement plan shall be subject to review and approval 
9by the Commission according to the provisions set forth in 
10this Section. A procurement plan shall include each of the 
11following components:
12  (1) Hourly load analysis. This analysis shall include:
13   (i) multi-year historical analysis of hourly 
14 loads;
15   (ii) switching trends and competitive retail 
16 market analysis;
17   (iii) known or projected changes to future loads; 
18 and
19   (iv) growth forecasts by customer class.
20  (2) Analysis of the impact of any demand side and 
21 renewable energy initiatives. This analysis shall include:
22   (i) the impact of demand response programs and 
23 energy efficiency programs, both current and 
24 projected; for small multi-jurisdictional utilities, 
25 the impact of demand response and energy efficiency 
26 programs approved pursuant to Section 8-408 of this 
 
 
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1 Act, both current and projected; and
2   (ii) supply side needs that are projected to be 
3 offset by purchases of renewable energy resources, if 
4 any.
5  (3) A plan for meeting the expected load requirements 
6 that will not be met through preexisting contracts. This 
7 plan shall include:
8   (i) definitions of the different Illinois retail 
9 customer classes for which supply is being purchased;
10   (ii) the proposed mix of demand-response products 
11 for which contracts will be executed during the next 
12 year. For small multi-jurisdictional electric 
13 utilities that on December 31, 2005 served fewer than 
14 100,000 customers in Illinois, these shall be defined 
15 as demand-response products offered in an energy 
16 efficiency plan approved pursuant to Section 8-408 of 
17 this Act. The cost-effective demand-response measures 
18 shall be procured whenever the cost is lower than 
19 procuring comparable capacity products, provided that 
20 such products shall: 
21    (A) be procured by a demand-response provider 
22 from those retail customers included in the plan's 
23 electric supply service requirements;
24    (B) at least satisfy the demand-response 
25 requirements of the regional transmission 
26 organization market in which the utility's service 
 
 
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1 territory is located, including, but not limited 
2 to, any applicable capacity or dispatch 
3 requirements;
4    (C) provide for customers' participation in 
5 the stream of benefits produced by the 
6 demand-response products;
7    (D) provide for reimbursement by the 
8 demand-response provider of the utility for any 
9 costs incurred as a result of the failure of the 
10 supplier of such products to perform its 
11 obligations thereunder; and
12    (E) meet the same credit requirements as apply 
13 to suppliers of capacity, in the applicable 
14 regional transmission organization market; 
15   (iii) monthly forecasted system supply 
16 requirements, including expected minimum, maximum, and 
17 average values for the planning period;
18   (iv) the proposed mix and selection of standard 
19 wholesale products for which contracts will be 
20 executed during the next year, separately or in 
21 combination, to meet that portion of its load 
22 requirements not met through pre-existing contracts, 
23 including but not limited to monthly 5 x 16 peak period 
24 block energy, monthly off-peak wrap energy, monthly 7 
25 x 24 energy, annual 5 x 16 energy, other standardized 
26 energy or capacity products designed to provide 
 
 
SB2552- 97 -LRB103 31416 LNS 59082 b


1 eligible retail customer benefits from commercially 
2 deployed advanced technologies including but not 
3 limited to high voltage direct current converter 
4 stations, as such term is defined in Section 1-10 of 
5 the Illinois Power Agency Act, whether or not such 
6 product is currently available in wholesale markets, 
7 annual off-peak wrap energy, annual 7 x 24 energy, 
8 monthly capacity, annual capacity, peak load capacity 
9 obligations, capacity purchase plan, and ancillary 
10 services;
11   (v) proposed term structures for each wholesale 
12 product type included in the proposed procurement plan 
13 portfolio of products; and
14   (vi) an assessment of the price risk, load 
15 uncertainty, and other factors that are associated 
16 with the proposed procurement plan; this assessment, 
17 to the extent possible, shall include an analysis of 
18 the following factors: contract terms, time frames for 
19 securing products or services, fuel costs, weather 
20 patterns, transmission costs, market conditions, and 
21 the governmental regulatory environment; the proposed 
22 procurement plan shall also identify alternatives for 
23 those portfolio measures that are identified as having 
24 significant price risk and mitigation in the form of 
25 additional retail customer and ratepayer price, 
26 reliability, and environmental benefits from 
 
 
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1 standardized energy products delivered from 
2 commercially deployed advanced technologies, 
3 including, but not limited to, high voltage direct 
4 current converter stations, as such term is defined in 
5 Section 1-10 of the Illinois Power Agency Act, whether 
6 or not such product is currently available in 
7 wholesale markets.
8  (4) Proposed procedures for balancing loads. The 
9 procurement plan shall include, for load requirements 
10 included in the procurement plan, the process for (i) 
11 hourly balancing of supply and demand and (ii) the 
12 criteria for portfolio re-balancing in the event of 
13 significant shifts in load.
14  (5) Long-Term Renewable Resources Procurement Plan. 
15 The Agency shall prepare a long-term renewable resources 
16 procurement plan for the procurement of renewable energy 
17 credits under Sections 1-56 and 1-75 of the Illinois Power 
18 Agency Act for delivery beginning in the 2017 delivery 
19 year.
20   (i) The initial long-term renewable resources 
21 procurement plan and all subsequent revisions shall be 
22 subject to review and approval by the Commission. For 
23 the purposes of this Section, "delivery year" has the 
24 same meaning as in Section 1-10 of the Illinois Power 
25 Agency Act. For purposes of this Section, "Agency" 
26 shall mean the Illinois Power Agency.
 
 
SB2552- 99 -LRB103 31416 LNS 59082 b


1   (ii) The long-term renewable resources planning 
2 process shall be conducted as follows:
3    (A) Electric utilities shall provide a range 
4 of load forecasts to the Illinois Power Agency 
5 within 45 days of the Agency's request for 
6 forecasts, which request shall specify the length 
7 and conditions for the forecasts including, but 
8 not limited to, the quantity of distributed 
9 generation expected to be interconnected for each 
10 year.
11    (B) The Agency shall publish for comment the 
12 initial long-term renewable resources procurement 
13 plan no later than 120 days after the effective 
14 date of this amendatory Act of the 99th General 
15 Assembly and shall review, and may revise, the 
16 plan at least every 2 years thereafter. To the 
17 extent practicable, the Agency shall review and 
18 propose any revisions to the long-term renewable 
19 energy resources procurement plan in conjunction 
20 with the Agency's other planning and approval 
21 processes conducted under this Section. The 
22 initial long-term renewable resources procurement 
23 plan shall:
24     (aa) Identify the procurement programs and 
25 competitive procurement events consistent with 
26 the applicable requirements of the Illinois 
 
 
SB2552- 100 -LRB103 31416 LNS 59082 b


1 Power Agency Act and shall be designed to 
2 achieve the goals set forth in subsection (c) 
3 of Section 1-75 of that Act.
4     (bb) Include a schedule for procurements 
5 for renewable energy credits from 
6 utility-scale wind projects, utility-scale 
7 solar projects, and brownfield site 
8 photovoltaic projects consistent with 
9 subparagraph (G) of paragraph (1) of 
10 subsection (c) of Section 1-75 of the Illinois 
11 Power Agency Act.
12     (cc) Identify the process whereby the 
13 Agency will submit to the Commission for 
14 review and approval the proposed contracts to 
15 implement the programs required by such plan.
16    Copies of the initial long-term renewable 
17 resources procurement plan and all subsequent 
18 revisions shall be posted and made publicly 
19 available on the Agency's and Commission's 
20 websites, and copies shall also be provided to 
21 each affected electric utility. An affected 
22 utility and other interested parties shall have 45 
23 days following the date of posting to provide 
24 comment to the Agency on the initial long-term 
25 renewable resources procurement plan and all 
26 subsequent revisions. All comments submitted to 
 
 
SB2552- 101 -LRB103 31416 LNS 59082 b


1 the Agency shall be specific, supported by data or 
2 other detailed analyses, and, if objecting to all 
3 or a portion of the procurement plan, accompanied 
4 by specific alternative wording or proposals. All 
5 comments shall be posted on the Agency's and 
6 Commission's websites. During this 45-day comment 
7 period, the Agency shall hold at least one public 
8 hearing within each utility's service area that is 
9 subject to the requirements of this paragraph (5) 
10 for the purpose of receiving public comment. 
11 Within 21 days following the end of the 45-day 
12 review period, the Agency may revise the long-term 
13 renewable resources procurement plan based on the 
14 comments received and shall file the plan with the 
15 Commission for review and approval.
16    (C) Within 14 days after the filing of the 
17 initial long-term renewable resources procurement 
18 plan or any subsequent revisions, any person 
19 objecting to the plan may file an objection with 
20 the Commission. Within 21 days after the filing of 
21 the plan, the Commission shall determine whether a 
22 hearing is necessary. The Commission shall enter 
23 its order confirming or modifying the initial 
24 long-term renewable resources procurement plan or 
25 any subsequent revisions within 120 days after the 
26 filing of the plan by the Illinois Power Agency.
 
 
SB2552- 102 -LRB103 31416 LNS 59082 b


1    (D) The Commission shall approve the initial 
2 long-term renewable resources procurement plan and 
3 any subsequent revisions, including expressly the 
4 forecast used in the plan and taking into account 
5 that funding will be limited to the amount of 
6 revenues actually collected by the utilities, if 
7 the Commission determines that the plan will 
8 reasonably and prudently accomplish the 
9 requirements of Section 1-56 and subsection (c) of 
10 Section 1-75 of the Illinois Power Agency Act. The 
11 Commission shall also approve the process for the 
12 submission, review, and approval of the proposed 
13 contracts to procure renewable energy credits or 
14 implement the programs authorized by the 
15 Commission pursuant to a long-term renewable 
16 resources procurement plan approved under this 
17 Section.
18    In approving any long-term renewable resources 
19 procurement plan after the effective date of this 
20 amendatory Act of the 102nd General Assembly, the 
21 Commission shall approve or modify the Agency's 
22 proposal for minimum equity standards pursuant to 
23 subsection (c-10) of Section 1-75 of the Illinois 
24 Power Agency Act. The Commission shall consider 
25 any analysis performed by the Agency in developing 
26 its proposal, including past performance, 
 
 
SB2552- 103 -LRB103 31416 LNS 59082 b


1 availability of equity eligible contractors, and 
2 availability of equity eligible persons at the 
3 time the long-term renewable resources procurement 
4 plan is approved. 
5   (iii) The Agency or third parties contracted by 
6 the Agency shall implement all programs authorized by 
7 the Commission in an approved long-term renewable 
8 resources procurement plan without further review and 
9 approval by the Commission. Third parties shall not 
10 begin implementing any programs or receive any payment 
11 under this Section until the Commission has approved 
12 the contract or contracts under the process authorized 
13 by the Commission in item (D) of subparagraph (ii) of 
14 paragraph (5) of this subsection (b) and the third 
15 party and the Agency or utility, as applicable, have 
16 executed the contract. For those renewable energy 
17 credits subject to procurement through a competitive 
18 bid process under the plan or under the initial 
19 forward procurements for wind and solar resources 
20 described in subparagraph (G) of paragraph (1) of 
21 subsection (c) of Section 1-75 of the Illinois Power 
22 Agency Act, the Agency shall follow the procurement 
23 process specified in the provisions relating to 
24 electricity procurement in subsections (e) through (i) 
25 of this Section.
26   (iv) An electric utility shall recover its costs 
 
 
SB2552- 104 -LRB103 31416 LNS 59082 b


1 associated with the procurement of renewable energy 
2 credits under this Section and pursuant to subsection 
3 (c-5) of Section 1-75 of the Illinois Power Agency Act 
4 through an automatic adjustment clause tariff under 
5 subsection (k) or a tariff pursuant to subsection 
6 (i-5), as applicable, of Section 16-108 of this Act. A 
7 utility shall not be required to advance any payment 
8 or pay any amounts under this Section that exceed the 
9 actual amount of revenues collected by the utility 
10 under paragraph (6) of subsection (c) of Section 1-75 
11 of the Illinois Power Agency Act, subsection (c-5) of 
12 Section 1-75 of the Illinois Power Agency Act, and 
13 subsection (k) or subsection (i-5), as applicable, of 
14 Section 16-108 of this Act, and contracts executed 
15 under this Section shall expressly incorporate this 
16 limitation.
17   (v) For the public interest, safety, and welfare, 
18 the Agency and the Commission may adopt rules to carry 
19 out the provisions of this Section on an emergency 
20 basis immediately following the effective date of this 
21 amendatory Act of the 99th General Assembly.
22   (vi) On or before July 1 of each year, the 
23 Commission shall hold an informal hearing for the 
24 purpose of receiving comments on the prior year's 
25 procurement process and any recommendations for 
26 change. 
 
 
SB2552- 105 -LRB103 31416 LNS 59082 b


1 (b-5) An electric utility that as of January 1, 2019 
2served more than 300,000 retail customers in this State shall 
3purchase renewable energy credits from new renewable energy 
4facilities constructed at or adjacent to the sites of 
5coal-fueled electric generating facilities in this State in 
6accordance with subsection (c-5) of Section 1-75 of the 
7Illinois Power Agency Act. Except as expressly provided in 
8this Section, the plans and procedures for such procurements 
9shall not be included in the procurement plans provided for in 
10this Section, but rather shall be conducted and implemented 
11solely in accordance with subsection (c-5) of Section 1-75 of 
12the Illinois Power Agency Act. 
13 (b-10) Capacity procurement.
14  (1) Definitions. For purposes of this subsection:
15  "Applicable Local Resource Zone" means the Zone 4 
16 Local Resource Zone as set forth in the MISO Business 
17 Practices Manual 011 – Resource Adequacy, or any future 
18 successor zone for the same geographic space, as 
19 designated by MISO governing documents.
20  "Applicable locational deliverability area" means the 
21 ComEd Locational Deliverability Area as set forth in the 
22 PJM Manual, or any future successor area for the same 
23 geographic space, as designated by PJM governing 
24 documents.
25  "Electric cooperative" has the meaning given to that 
26 term in Section 3-119.
 
 
SB2552- 106 -LRB103 31416 LNS 59082 b


1  "Fixed Resource Adequacy Plan", "Local Clearing 
2 Requirement", "Local Resource Zone", "Planning Resource", 
3 and "Planning Reserve Margin Requirement" have the 
4 meanings given to those terms in the MISO Tariff, 
5 including as they may apply to individual Load Serving 
6 Entities, as applicable. For avoidance of doubt, these 
7 terms shall be interpreted as multiple seasonal values 
8 within a given delivery year if MISO's then-prevailing 
9 resource adequacy construct has a seasonal component.
10  "Load Serving Entity" has the meaning given to that 
11 term by the regional transmission organization where the 
12 entity serves customers, either in the Midcontinent 
13 Independent System Operator Tariff or PJM Interconnection, 
14 LLC Reliability Assurance Agreement. For entities that 
15 serve customers in multiple regional transmission 
16 organizations, their operations within each regional 
17 transmission organization shall be defined and subject to 
18 the definition set forth by the relevant regional 
19 transmission organization. "Load Serving Entity" includes 
20 any electric utility as defined in Section 16-102 of the 
21 Public Utilities Act or alternative retail electric 
22 supplier as defined in Section 16-102 of the Public 
23 Utilities Act. "Load Serving Entity" does not include 
24 municipal utilities, electric cooperatives, and multistate 
25 electric utilities.
26  "Midcontinent Independent System Operator" or "MISO" 
 
 
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1 means the Midcontinent Independent System Operator, Inc., 
2 or its successor approved by the federal Energy Regulatory 
3 Commission as the regional transmission organization for 
4 the Applicable Local Resource Zone.
5  "MISO Tariff" shall mean the open access transmission 
6 and energy markets tariff of the Midcontinent Independent 
7 System Operator, Inc. or its successor, as that tariff may 
8 be updated from time to time.
9  "Municipal utility" has the meaning given to that term 
10 in paragraph (1) of subsection (b) of Section 3-105.
11  "Peak Load Contribution" means the peak load 
12 contribution, calculated in the manner specified in the 
13 MISO Tariff, PJM Reliability Assurance Agreement, or other 
14 applicable governing documents by a regional transmission 
15 organization serving this State, of, as applicable, a 
16 retail customer, a group of customers served by a Load 
17 Serving Entity, or all customers of the Load Serving 
18 Entity in the Applicable Local Resource Zone or Locational 
19 Deliverability Area.
20  "PJM" means PJM Interconnection, LLC, or its successor 
21 approved by the federal Energy Regulatory Commission.
22  "PJM Open Access Transmission Tariff", "PJM Operating 
23 Agreement", "PJM Reliability Assurance Agreement", and 
24 "PJM Manual" means the respective governing documents of 
25 PJM Interconnection, LLC, or its successor, as it may be 
26 updated from time to time.
 
 
SB2552- 108 -LRB103 31416 LNS 59082 b


1  "PJM Region Reliability Requirement" and "Internal 
2 Resource Requirement" have the meaning given to those 
3 terms in the PJM Manual on the Capacity Market. For 
4 avoidance of doubt, this term shall be interpreted as 
5 multiple seasonal values within a given delivery year if 
6 PJM's then-prevailing resource adequacy construct has a 
7 seasonal component.
8  "Qualified resources" means:
(i) energy efficiency 
9 measures that are implemented pursuant to plans approved 
10 by the Commission under Sections 8-103, 8-103B, and 8-104;

11 (ii) wind, solar thermal energy, photovoltaic cells and 
12 panels, and hydropower;
(iii) demand response resources, 
13 as long as they do not involve fossil fuel generation; and

14 (iv) energy storage, as long as it was charged entirely 
15 with resources listed in item (ii).
16  (2) Capacity planning. The Agency shall conduct 
17 capacity procurement events to procure a target portion of 
18 capacity toward the Planning Reserve Margin Requirement 
19 for all Load Serving Entities serving customers within the 
20 Applicable Local Resource Zone and a target portion of 
21 capacity toward the PJM Region Reliability Requirement for 
22 Load Serving Entities serving customers within the 
23 Applicable Locational Deliverability Area, for delivery 
24 years as specified in this subsection.
25   (A) Capacity procurement mechanics.
26    (i) Capacity procurement schedules.
 
 
SB2552- 109 -LRB103 31416 LNS 59082 b


1    For the delivery year 2025-2026, the Agency 
2 shall procure capacity that is sufficient to meet 
3 at least 12% of the portion of the projected 
4 Planning Reserve Margin Requirement for Load 
5 Serving Entities serving customers within the 
6 Applicable Local Resource Zone, and 12% of the PJM 
7 Region Reliability Requirement for Load Serving 
8 Entities serving customers within the Applicable 
9 Locational Deliverability Area.
10    For the delivery year 2026-2027, the Agency 
11 shall procure capacity that is sufficient to meet 
12 at least 15% of the portion of the projected 
13 Planning Reserve Margin Requirement for Load 
14 Serving Entities serving customers within the 
15 Applicable Local Resource Zone, and 15% of the PJM 
16 Region Reliability Requirement for Load Serving 
17 Entities serving customers within the Applicable 
18 Locational Deliverability Area.
19    For the delivery year 2027-2028, the Agency 
20 shall procure capacity that is sufficient to meet 
21 at least 18% of the portion of the projected 
22 Planning Reserve Margin Requirement for Load 
23 Serving Entities serving customers within the 
24 Applicable Local Resource Zone, and 18% of the PJM 
25 Region Reliability Requirement for Load Serving 
26 Entities serving customers within the Applicable 
 
 
SB2552- 110 -LRB103 31416 LNS 59082 b


1 Locational Deliverability Area.
2    For the delivery year 2028-2029, the Agency 
3 shall procure capacity that is sufficient to meet 
4 at least 21% of the portion of the projected 
5 Planning Reserve Margin Requirement for Load 
6 Serving Entities serving customers within the 
7 Applicable Local Resource Zone, and 21% of the PJM 
8 Region Reliability Requirement for Load Serving 
9 Entities serving customers within the Applicable 
10 Locational Deliverability Area.
11    For the delivery year 2029-2030, the Agency 
12 shall procure capacity that is sufficient to meet 
13 at least 24% of the portion of the projected 
14 Planning Reserve Margin Requirement for Load 
15 Serving Entities serving customers within the 
16 Applicable Local Resource Zone, and 24% of the PJM 
17 Region Reliability Requirement for Load Serving 
18 Entities serving customers within the Applicable 
19 Locational Deliverability Area.
20    For the delivery year 2030-2031, the Agency 
21 shall procure capacity that is sufficient to meet 
22 at least 27% of the portion of the projected 
23 Planning Reserve Margin Requirement for Load 
24 Serving Entities serving customers within the 
25 Applicable Local Resource Zone, and 27% of the PJM 
26 Region Reliability Requirement for Load Serving 
 
 
SB2552- 111 -LRB103 31416 LNS 59082 b


1 Entities serving customers within the Applicable 
2 Locational Deliverability Area.
3    For the delivery year 2031-2032, the Agency 
4 shall procure capacity that is sufficient to meet 
5 at least 30% of the portion of the projected 
6 Planning Reserve Margin Requirement for Load 
7 Serving Entities serving customers within the 
8 Applicable Local Resource Zone, and 30% of the PJM 
9 Region Reliability Requirement for Load Serving 
10 Entities serving customers within the Applicable 
11 Locational Deliverability Area.
12    For the delivery year 2032-2033, the Agency 
13 shall procure capacity that is sufficient to meet 
14 at least 33% of the portion of the projected 
15 Planning Reserve Margin Requirement for Load 
16 Serving Entities serving customers within the 
17 Applicable Local Resource Zone, and 33% of the PJM 
18 Region Reliability Requirement for Load Serving 
19 Entities serving customers within the Applicable 
20 Locational Deliverability Area.
21    For the delivery year 2033-2034, the Agency 
22 shall procure capacity that is sufficient to meet 
23 at least 36% of the portion of the projected 
24 Planning Reserve Margin Requirement for Load 
25 Serving Entities serving customers within the 
26 Applicable Local Resource Zone, and 36% of the PJM 
 
 
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1 Region Reliability Requirement for Load Serving 
2 Entities serving customers within the Applicable 
3 Locational Deliverability Area.
4    For the delivery year 2034-2035, the Agency 
5 shall procure capacity that is sufficient to meet 
6 at least 39% of the portion of the projected 
7 Planning Reserve Margin Requirement for Load 
8 Serving Entities serving customers within the 
9 Applicable Local Resource Zone, and 39% of the PJM 
10 Region Reliability Requirement for Load Serving 
11 Entities serving customers within the Applicable 
12 Locational Deliverability Area.
13    For the delivery year 2035-2036, the Agency 
14 shall procure capacity that is sufficient to meet 
15 at least 42% of the portion of the projected 
16 Planning Reserve Margin Requirement for Load 
17 Serving Entities serving customers within the 
18 Applicable Local Resource Zone, and 42% of the PJM 
19 Region Reliability Requirement for Load Serving 
20 Entities serving customers within the Applicable 
21 Locational Deliverability Area.
22    (ii) For all the procurement events described 
23 in this subsection, any capacity procured must be 
24 attributable to the projected load of the 
25 customers of each Load Serving Entity. The 
26 contract buyer shall be, for all resulting 
 
 
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1 contracts as described in paragraph (7), the 
2 largest electric utility located in MISO for 
3 procured capacity that satisfies Load Serving 
4 Entities' customer requirements in the Applicable 
5 Local Resource Zone, and the largest electric 
6 utility located in PJM for procured capacity that 
7 satisfies Load Serving Entities' customer 
8 requirements in the Applicable Locational 
9 Deliverability Area. Following receipt of the 
10 product under each contract, the contract buyer 
11 shall timely transfer procured capacity credits to 
12 other Load Serving Entities in the same regional 
13 transmission organization, following the 
14 applicable prevailing rules for transfer of 
15 capacity credits under the MISO Tariff or PJM Open 
16 Access Transmission Tariff, based on the 
17 allocation described in subparagraph (A) of 
18 paragraph (7).
19    (iii) For all procurement events described in 
20 this subsection, the Agency may use its discretion 
21 in determining how much capacity it procures in 
22 each procurement event, so long as the cumulative 
23 procurement of Agency-procured capacity for a 
24 given delivery year by the time of that delivery 
25 year is equal, for both the Applicable Local 
26 Resource Zone and Applicable Locational 
 
 
SB2552- 114 -LRB103 31416 LNS 59082 b


1 Deliverability Area, to the target percentage for 
2 that delivery year. The Agency may hold 
3 procurement events for a target delivery year 
4 during the period January 1 to March 1 of the 
5 calendar year in which the target delivery year 
6 begins, or during the period January 1 to March 1 
7 of either of the 2 previous calendar years. The 
8 Agency shall endeavor to complete capacity 
9 procurement events on a schedule so that procured 
10 capacity credits for a delivery year covered by an 
11 immediately upcoming regional transmission 
12 organization capacity auction may be timely 
13 submitted by Load Serving Entities to the 
14 applicable regional transmission organization.
15    (iv) The Agency, at its discretion, may 
16 procure qualified resources as defined in 
17 subparagraph (B) to meet the target portion of 
18 capacity for a given delivery year, further in 
19 advance than the timelines given in item (iii), as 
20 long as the contracts do not exceed 15 years in 
21 length. Resources that are not qualified resources 
22 as defined in subparagraph (B) may not be procured 
23 under this item.
24    (v) Each of the Load Serving Entities shall 
25 annually report its capacity commitments resulting 
26 from the procurement events described in this 
 
 
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1 subsection, based on the allocation described in 
2 subparagraph (A) of paragraph (7), in accordance 
3 with the applicable provisions of the PJM Open 
4 Access Transmission Tariff, the applicable 
5 provisions of the MISO Tariff, and other official 
6 standards of regional transmission organizations 
7 as appropriate.
8    (vi) The capacity procurement plans developed 
9 by the Agency and the capacity procurement events 
10 shall be designed to procure capacity to ensure 
11 long-term resource adequacy at the lowest 
12 environmentally safe cost over time, taking into 
13 account the benefits of price stability and the 
14 need to ensure the reliability, adequacy, and 
15 resilience of the bulk power generation and 
16 delivery system, as well as the health and climate 
17 impacts of various capacity resources. The 
18 procurement shall not interfere with the emissions 
19 reductions required in Section 9.15 of the 
20 Environmental Protection Act and the procurement 
21 shall be in keeping with the goals of the Paris 
22 Climate Agreement, to limit the rise in mean 
23 global temperature to well below 2 degrees Celsius 
24 (3.6 degrees Fahrenheit) above preindustrial 
25 levels, and preferably limit the increase to 1.5 
26 degrees Celsius (2.7 degrees Fahrenheit).
 
 
SB2552- 116 -LRB103 31416 LNS 59082 b


1   (B) Clean capacity. A percentage of the total 
2 capacity procured according to subparagraph (A) shall 
3 be from qualified resources with the goals of reducing 
4 pollution from the power sector, lowering consumer 
5 costs, and creating investment opportunities for new 
6 renewable resources.
Capacity procurements conducted 
7 under subparagraph (A) shall contain the following 
8 percentage of qualified resources: 25% of the total 
9 amount procured in the capacity procurement events 
10 conducted in 2025, increasing at least 3 percentage 
11 points per delivery year to reach 40% by 2030 and 
12 continuing at no less than 40% each year thereafter.

13 The Agency may procure capacity from qualified 
14 resources described in this subparagraph using 
15 contract durations of up to 15 years. Capacity from 
16 these qualified resources counts toward the capacity 
17 procurement amounts described in subparagraph (A).
18   (C) In determining or projecting the capacity 
19 obligation attributable to the customers of the Load 
20 Serving Entity for a delivery year for purposes of 
21 capacity procurement plans and capacity procurement 
22 events under this subsection, the Agency and, as 
23 applicable, the procurement administrator shall use, 
24 as applicable, the Planning Reserve Margin Requirement 
25 and Peak Load Contribution, as established or 
26 projected by the Midcontinent Independent System 
 
 
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1 Operator or the PJM Region Reliability Requirement as 
2 established or projected by PJM Interconnection, LLC. 
3 If the Midcontinent Independent System Operator or PJM 
4 Interconnection, LLC have not established or released 
5 a projection of these figures a delivery year, the 
6 Agency and, as applicable, the procurement 
7 administrator shall develop forecasts of the Planning 
8 Reserve Margin Requirement, Peak Load Contribution, 
9 PJM Region Reliability Requirement, and other relevant 
10 figures used by the Midcontinent Independent System 
11 Operator and PJM Interconnection, LLC to maintain 
12 reliability, respectively, in the Applicable Local 
13 Resource Zone and Applicable Locational Deliverability 
14 Area for that delivery year based on available 
15 information, including, without limiting the 
16 foregoing, the most recent Planning Reserve Margin 
17 Requirement, Peak Load Contribution, and established 
18 by the Midcontinent Independent System Operator, and 
19 the most recent PJM Region Reliability Requirement 
20 established by PJM Interconnection, LLC for a delivery 
21 year and any other information from the Midcontinent 
22 Independent System Operator, PJM Interconnection, LLC, 
23 and the Load Serving Entity. If requested by the 
24 Agency, the Load Serving Entity shall provide to the 
25 Agency actual and forecasted peak electric load 
26 information for the customers of the Load Serving 
 
 
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1 Entity in the Applicable Local Resource Zone and PJM 
2 Region Reliability Requirement.
3  (3)
(A) Each capacity procurement event may include 
4 the procurement of capacity through a mix of contracts 
5 with different terms and different initial delivery dates 
6 as proposed by the Agency in its capacity procurement plan 
7 and approved by the Commission, so long as each annual 
8 capacity procurement event results in the procurement of 
9 an amount of capacity that, together with capacity 
10 procured in previous capacity procurement events, is equal 
11 to the portion or portions of the projected Planning 
12 Reserve Margin Requirement (for Load Serving Entities in 
13 MISO) and PJM Region Reliability Requirement (for Load 
14 Serving Entities in PJM) for the delivery year or delivery 
15 years for which capacity is to be procured as specified in 
16 paragraph (2). Each capacity procurement event shall 
17 specify all Load Serving Entities for which capacity is 
18 ultimately being procured, and indicate their projected 
19 shares of the targeted capacity, consistent with 
20 subparagraph (A) of paragraph (7).
21  (B) The Agency's annual capacity procurement plans for 
22 the Applicable Local Resource Zone shall be developed as 
23 follows: No later than July 15 of each year, the Agency 
24 shall post on its website and otherwise make publicly 
25 available, for public comment, its draft capacity 
26 procurement plan for the capacity procurement event to be 
 
 
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1 held in February of the following calendar year. 
2 Interested parties shall be allowed 30 days from the 
3 posting of the draft capacity procurement plan to submit 
4 comments to the Agency. The Agency shall consider any 
5 comments received and shall file its proposed capacity 
6 procurement plan with the Commission within 15 days 
7 following the conclusion of the public comment period. The 
8 Commission shall open a docketed proceeding for 
9 consideration and approval or modification of the proposed 
10 capacity procurement plan. The Commission or its 
11 administrative law judge assigned to the proceeding shall 
12 establish a procedural schedule for the proceeding that 
13 will enable the Commission to issue an order, within 90 
14 days following the date the capacity procurement plan was 
15 filed with the Commission, approving, with any 
16 modifications directed by the Commission, the capacity 
17 procurement plan. On or before December 1 each year, the 
18 Commission shall issue its order in the proceeding 
19 approving, or approving with modifications, the capacity 
20 procurement plan. For the initial capacity procurement 
21 event to be conducted in 2025: (i) the Agency shall file 
22 its proposed capacity procurement plan with the Commission 
23 within 30 days following the effective date of this 
24 amendatory Act of the 103rd General Assembly; (ii) the 
25 Commission, after notice and hearing, shall approve the 
26 capacity procurement plan, with such modifications as 
 
 
SB2552- 120 -LRB103 31416 LNS 59082 b


1 directed by the Commission, within 30 days following the 
2 date that the proposed capacity procurement plan was filed 
3 with the Commission; and (iii) the capacity procurement 
4 event shall be held no later than March 1, 2025.
5  (C) The Agency shall meet the goals and requirements 
6 of this subsection prior to considering any of the other 
7 capacity procurement goals, options, or requirements of 
8 this Section (including those set out in subparagraphs 
9 (ii) and (iv) of paragraph (3) of subsection (b)).
10  (4) To the extent that any other provision of this 
11 Section or any provision of the Illinois Power Agency Act 
12 are not inconsistent with the provisions of this 
13 subsection for, and are otherwise applicable to, capacity 
14 procurement events conducted under this subsection, those 
15 other provisions shall be used in conducting capacity 
16 procurement events conducted under this subsection.
17  (5) The capacity procurement plans prepared by, and 
18 the capacity procurement events conducted by, the Agency 
19 under this subsection shall be subject to the following 
20 requirements:
21   (A) The mix of capacity resources selected in any 
22 procurement event conducted under this subsection must 
23 include sufficient qualified Zonal Resource Credits 
24 (for Load Serving Entities in MISO) or accredited 
25 megawatts (for Load Serving Entities in PJM), together 
26 with capacity procured in previous capacity 
 
 
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1 procurement events, to satisfy the portion specified 
2 in item (i) of subparagraph (a) of paragraph (2) of the 
3 Applicable Local Resource Zone and Applicable 
4 Locational Deliverability Area and must otherwise be 
5 consistent with the requirements for capacity 
6 established by the Midcontinent Independent System 
7 Operator and PJM Interconnection LLC. The procurement 
8 of capacity in the capacity procurement events shall 
9 not include the portion of the Planning Reserve Margin 
10 Requirement for the Applicable Local Resource Zone or 
11 Applicable Locational Deliverability Area associated 
12 with customers served by a municipal utility, an 
13 electric cooperative, or a multistate electric 
14 utility.
15   (B) The capacity to be procured for each delivery 
16 year for Load Serving Entities in MISO shall include 
17 an amount of capacity from capacity resources 
18 physically located within the Applicable Local 
19 Resource Zone that is no less than the portion of the 
20 projected Local Clearing Requirement for the 
21 Applicable Local Resource Zone for that delivery year 
22 attributable to the load of the customers of the Load 
23 Serving Entities. The capacity to be procured for each 
24 delivery year for Load Serving Entities in PJM shall 
25 include an amount of capacity from capacity resources 
26 physically located within the Applicable Locational 
 
 
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1 Deliverability Area that represents a percentage 
2 equaling at least the Internal Resource Requirement 
3 for the Applicable Locational Deliverability Area as 
4 set by PJM.
5   (C) In each capacity procurement plan, the Agency 
6 shall include a discussion of whether factors, other 
7 than price, to support reliability in the Applicable 
8 Local Resource Zone or Applicable Locational 
9 Deliverability Area should be taken into account in 
10 selecting capacity resources in the capacity 
11 procurement event or events that are the subject of 
12 the capacity procurement plan. The Agency may propose 
13 in the capacity procurement plan to procure a 
14 specified amount or amounts of capacity from capacity 
15 resources located within the Applicable Local Resource 
16 Zone and Applicable Locational Deliverability Area, 
17 over and above the amount of capacity required to 
18 satisfy the Planning Resource Margin Requirement or 
19 PJM Region Reliability Requirement, as applicable, to 
20 support reliability within the Applicable Local 
21 Resource Zone or Applicable Locational Deliverability 
22 Area, including, but not limited to, for purposes of 
23 transmission security, voltage support, dynamic 
24 stability, frequency response, fuel security and 
25 on-site fuel supply, public health benefits, and 
26 import transfer capability. The inclusion of any such 
 
 
SB2552- 123 -LRB103 31416 LNS 59082 b


1 factors in the capacity procurement plan shall be 
2 subject to approval of the Commission.
3   (D) Any capacity resource, including, without 
4 limitation, demand response resources, energy 
5 efficiency resources, and renewable energy resources, 
6 that meets the other eligibility requirements of this 
7 subsection shall be eligible to participate in a 
8 capacity procurement event under this subsection if, 
9 and to the extent that, the resource satisfies all the 
10 requirements of the MISO Tariff, PJM Reliability 
11 Assurance Agreement, or other appropriate standards 
12 from regional transmission organizations or their 
13 successors. A municipal utility, an electric 
14 cooperative, a municipal electric power agency or 
15 other group, association, or consortium of municipal 
16 utilities or electric cooperatives may participate in 
17 a capacity procurement event, using capacity that it 
18 owns or leases, only to the extent that the owned and 
19 leased capacity of the municipal utility, electric 
20 cooperative, municipal electric power agency, or 
21 group, association, or consortium exceeds the Planning 
22 Reserve Margin Requirement or PJM Region Reliability 
23 Requirement, as applicable, attributable to the load 
24 of the customers that the municipal utility, electric 
25 cooperative, municipal electric power agency, or 
26 group, association, or consortium is obligated to 
 
 
SB2552- 124 -LRB103 31416 LNS 59082 b


1 serve. As a condition to eligibility to participate in 
2 a capacity procurement event conducted under this 
3 subsection, each municipal utility, electric 
4 cooperative, municipal electric power agency, and 
5 group, association, and consortium of municipal 
6 utilities or electric cooperatives shall certify its 
7 compliance with this requirement to the Agency for the 
8 capacity procurement event. A municipal utility, 
9 electric cooperative, municipal electric power agency, 
10 and group, association, or consortium of municipal 
11 utilities or electric cooperatives may not enter or 
12 bid any resources into a capacity procurement event if 
13 those resources use coal as a fuel.
14   (E) Capacity awarded in the Peak Time Rewards or 
15 Peak Time Savings program or successor program, if 
16 any, of an Load Serving Entity that is an electric 
17 utility shall be included in the capacity resources 
18 selected for each delivery year for which capacity is 
19 procured in a capacity procurement event, at a price 
20 for that delivery year equal to the weighted average 
21 price of the other capacity resources selected under 
22 this subsection for the delivery year. Prior to a 
23 capacity procurement event being conducted under this 
24 subsection to procure capacity for a delivery year, 
25 the Load Serving Entity shall notify the Agency and 
26 the procurement administrator of the amount of 
 
 
SB2552- 125 -LRB103 31416 LNS 59082 b


1 capacity awarded or forecasted to be awarded in the 
2 Peak Time Rewards program for each delivery year for 
3 which capacity is to be procured in the capacity 
4 procurement event. For purposes of contract 
5 administration and settlements, the Load Serving 
6 Entity shall be deemed the capacity supplier of 
7 capacity awarded in its Peak Time Rewards program or 
8 successor program.
9  (6) Each (i) capacity supplier selected in a capacity 
10 procurement event conducted by the Agency under this 
11 subsection and (ii) each Load Serving Entity that is an 
12 electric utility within the applicable regional 
13 transmission organization shall enter into contracts for 
14 capacity developed by the procurement administrator in 
15 accordance with paragraph (7).
16  (7) The procurement administrator, in conjunction with 
17 the Agency and the staff of the Commission and based on 
18 consultation with prospective capacity suppliers and with 
19 electric utilities, shall adopt, and shall revise from 
20 time to time as necessary and appropriate, standard form 
21 contracts to be entered into between the electric 
22 utilities and capacity suppliers selected in procurement 
23 events conducted under this subsection. The standard form 
24 contracts to be used in connection with each capacity 
25 procurement event conducted under this subsection shall be 
26 made available to prospective capacity suppliers prior to 
 
 
SB2552- 126 -LRB103 31416 LNS 59082 b


1 the capacity procurement event. Each capacity supplier 
2 seeking to participate in a capacity procurement event 
3 shall agree, as a condition of eligibility to participate, 
4 that if selected, it will enter into the standard form 
5 contract with the applicable electric utility located in 
6 the relevant regional transmission organization territory. 
7 The standard form contracts shall contain, without 
8 limitation, the following provisions:
9   (A) Each contract between a capacity supplier and 
10 an electric utility as buyer shall specify in an 
11 addendum that the capacity to be provided by the 
12 capacity supplier shall be ultimately allocated to 
13 each Load Serving Entity serving customers in the 
14 Applicable Local Resource Zone or Applicable 
15 Locational Deliverability Area, as applicable, where 
16 that portion of the total capacity to be supplied by 
17 the capacity supplier for any given Load Serving 
18 Entity, consistent with the transfer described in part 
19 item (ii) of subparagraph (A) of paragraph (2), shall 
20 equal the load ratio share of the Load Serving 
21 Entity's customers served by the Load Serving Entity 
22 as a percentage of the total Planning Reserve Margin 
23 Requirement or PJM Region Reliability Requirement, as 
24 applicable, attributable to the load of all Load 
25 Serving Entities customers in the Applicable Local 
26 Resource Zone or Applicable Locational Deliverability 
 
 
SB2552- 127 -LRB103 31416 LNS 59082 b


1 Area, as applicable, on March 1 immediately preceding 
2 the first delivery year for which the contract is in 
3 effect.
4   (B) The standard form contracts shall specify that 
5 if the Agency determines between March 1 and June 1 of 
6 a calendar year that the aggregate amount of capacity 
7 procured in capacity procurement events for the 
8 immediately upcoming delivery year beginning June 1 
9 exceeds the amount of capacity needed to meet the 
10 targeted portion of Planning Reserve Margin 
11 Requirement attributable to the load of the customers 
12 of all Load Serving Entities in the Applicable Local 
13 Resource Zone, or the PJM Region Reliability 
14 Requirement in the Applicable Locational 
15 Deliverability Area, as applicable, and directs that 
16 the capacity to be supplied by each capacity supplier 
17 for the immediately upcoming delivery year beginning 
18 June 1 shall be reduced on a pro rata basis so that the 
19 aggregate amount of capacity to be supplied for the 
20 immediately upcoming delivery year is equal to the 
21 amount of capacity needed to meet the targeted portion 
22 of the Planning Reserve Margin Requirement 
23 attributable to the load of the customers of all Load 
24 Serving Entities in the Applicable Local Resource 
25 Zone, or the PJM Region Reliability Requirement in the 
26 Applicable Locational Deliverability Area, as 
 
 
SB2552- 128 -LRB103 31416 LNS 59082 b


1 applicable, then the amount of capacity to be supplied 
2 and purchased under each contract between a capacity 
3 supplier and a Load Serving Entity that is an electric 
4 utility shall be deemed reduced as directed by the 
5 Agency. The standard form contract shall specify that 
6 any such reduction in the capacity to be supplied 
7 under the contract shall apply only to the immediately 
8 upcoming delivery year and not to any subsequent years 
9 in the contract term. The standard form contracts 
10 shall provide that in the event of a reduction in the 
11 capacity to be supplied in accordance with this 
12 subparagraph, the capacity supplier may resell or 
13 otherwise dispose of the capacity it is no longer 
14 obligated to supply.
15   (C) Each Load Serving Entity's allocated share of 
16 procured capacity in an Applicable Local Resource Zone 
17 or Applicable Locational Deliverability Area, as 
18 applicable, as originally determined as described in 
19 subparagraph (A), shall be deemed adjusted on a daily 
20 basis to be equal to the load ratio share of the Load 
21 Serving Entity's customers in the Applicable Local 
22 Resource Zone or Applicable Locational Deliverability 
23 Area, as applicable, that are served by the Load 
24 Serving Entity to the total Planning Reserve Margin 
25 Requirement or PJM Region Reliability Requirement, as 
26 applicable, attributable to the load of all the Load 
 
 
SB2552- 129 -LRB103 31416 LNS 59082 b


1 Serving Entities' customers in the Applicable Local 
2 Resource Zone or Applicable Locational Deliverability 
3 Area, as applicable, on that day. Based on the 
4 calculations in this subparagraph, the invoice amounts 
5 described in paragraph (8) shall include true-ups as 
6 appropriate.
7   (D) The standard form contracts shall specify the 
8 frequency of billing periods and payment remittance 
9 periods for the capacity supplier to bill the electric 
10 utility, and the electric utility to remit payment to 
11 the capacity supplier, for the capacity provided by 
12 the capacity supplier to the electric utility under 
13 the contract on each day during the billing period. A 
14 capacity supplier and an electric utility may agree to 
15 modify their contract to provide for billing and 
16 payment remittance periods other than the billing and 
17 payment dates specified in the standard form 
18 contracts.
19   (E) The standard form contracts shall include 
20 provisions relating to the credit, collateral, 
21 performance, and dispute resolution obligations of the 
22 parties, and other terms and conditions as described 
23 in paragraph (2) of subsection (e).
24   (F) The standard form contracts shall memorialize 
25 that other Load Serving Entities in the contract 
26 buyer's regional transmission organization, as 
 
 
SB2552- 130 -LRB103 31416 LNS 59082 b


1 identified as described in subparagraph (A), shall be 
2 considered as third-party beneficiaries of the 
3 contracts but shall not have contractual rights or 
4 remedies against the contract seller.
5   (G) The standard form contracts shall provide for 
6 the capacity supplier to take financial responsibility 
7 to make whole all Load Serving Entities for whom 
8 capacity is procured, if the applicable regional 
9 transmission organization ultimately disqualifies or 
10 imposes any nonperformance penalties in the applicable 
11 delivery year with respect to the procured capacity 
12 credits.
13  (8)
(A) Each contract buyer shall invoice all other 
14 Load Serving Entities in the Applicable Local Resource 
15 Zone or Applicable Locational Deliverability Area, as 
16 applicable, for their allocated share of capacity payments 
17 actually made under each contract, as determined in 
18 subparagraph (A) of paragraph (7) as modified by 
19 subparagraphs (B) and (C). Each Load Serving Entity that 
20 is an alternative retail electric supplier shall promptly 
21 pay the contract buyer upon receiving the invoice.
22  (B) Each Load Serving Entity that is an alternative 
23 retail electric supplier shall be allowed to recover and 
24 shall be responsible for recovering its costs for capacity 
25 incurred under contracts entered into under this 
26 subsection in accordance with its contracts and 
 
 
SB2552- 131 -LRB103 31416 LNS 59082 b


1 arrangements entered into with its customers. A Load 
2 Serving Entity that is an electric utility shall recover 
3 its costs for capacity incurred under contracts entered 
4 into under this subsection in accordance with the electric 
5 utility's tariff or other cost recovery mechanism approved 
6 by the Commission under subsection (l).
7  (9) Nothing in this subsection is intended to preclude 
8 the Agency or the Commission from conducting the 
9 procurement events and processes described in this 
10 subsection in conjunction with other procurement processes 
11 described in this Section or Section 1-75 of the Illinois 
12 Power Agency Act, to the extent the Agency and the 
13 Commission find that approach is appropriate and 
14 practicable while allowing the annual capacity procurement 
15 plans to be developed and submitted by the Agency and 
16 approved by the Commission in accordance with the schedule 
17 set forth in subparagraph (B) of paragraph (3), and 
18 allowing the capacity procurement events to be conducted 
19 within the time periods specified in this subsection.
20  (10) It is the intent of this subsection that the 
21 Agency's and the Commission's implementation of this 
22 subsection, including, but not limited to, the timing and 
23 number of procurement events and the duration of 
24 contracts, shall conform, at a minimum, to any applicable 
25 requirements of the MISO Tariff and PJM Open Access 
26 Transmission Tariff, as the MISO Tariff or PJM Open Access 
 
 
SB2552- 132 -LRB103 31416 LNS 59082 b


1 Transmission Tariff may be changed, replaced, or 
2 superseded from time to time, that are necessary for Load 
3 Serving Entities serving State customers to (if in MISO 
4 service territory) exercise and implement the Fixed 
5 Resource Adequacy Plan capacity procurement option, or (if 
6 in PJM service territory) to offset their Locational 
7 Reliability Charge, or in either case a successor capacity 
8 procurement mechanism. Notwithstanding anything to the 
9 contrary, the Agency and the Commission shall have the 
10 authority to take all steps necessary to implement this 
11 subsection consistent with applicable federal tariffs, and 
12 as those tariffs may be changed, replaced, or superseded 
13 from time to time, to procure capacity for the electric 
14 load of customers of Load Serving Entities subject to the 
15 requirements of this subsection. 
16 (c) The provisions of this subsection (c) shall not apply 
17to procurements conducted pursuant to subsection (c-5) of 
18Section 1-75 of the Illinois Power Agency Act. However, the 
19Agency may retain a procurement administrator to assist the 
20Agency in planning and carrying out the procurement events and 
21implementing the other requirements specified in such 
22subsection (c-5) of Section 1-75 of the Illinois Power Agency 
23Act, with the costs incurred by the Agency for the procurement 
24administrator to be recovered through fees charged to 
25applicants for selection to sell and deliver renewable energy 
26credits to electric utilities pursuant to subsection (c-5) of 
 
 
SB2552- 133 -LRB103 31416 LNS 59082 b


1Section 1-75 of the Illinois Power Agency Act. The procurement 
2process set forth in Section 1-75 of the Illinois Power Agency 
3Act and subsection (e) of this Section shall be administered 
4by a procurement administrator and monitored by a procurement 
5monitor.
6  (1) The procurement administrator shall:
7   (i) design the final procurement process in 
8 accordance with Section 1-75 of the Illinois Power 
9 Agency Act and subsection (e) of this Section 
10 following Commission approval of the procurement plan;
11   (ii) develop benchmarks in accordance with 
12 subsection (e)(3) to be used to evaluate bids; these 
13 benchmarks shall be submitted to the Commission for 
14 review and approval on a confidential basis prior to 
15 the procurement event;
16   (iii) serve as the interface between the electric 
17 utility and suppliers;
18   (iv) manage the bidder pre-qualification and 
19 registration process;
20   (v) obtain the electric utilities' agreement to 
21 the final form of all supply contracts and credit 
22 collateral agreements;
23   (vi) administer the request for proposals process;
24   (vii) have the discretion to negotiate to 
25 determine whether bidders are willing to lower the 
26 price of bids that meet the benchmarks approved by the 
 
 
SB2552- 134 -LRB103 31416 LNS 59082 b


1 Commission; any post-bid negotiations with bidders 
2 shall be limited to price only and shall be completed 
3 within 24 hours after opening the sealed bids and 
4 shall be conducted in a fair and unbiased manner; in 
5 conducting the negotiations, there shall be no 
6 disclosure of any information derived from proposals 
7 submitted by competing bidders; if information is 
8 disclosed to any bidder, it shall be provided to all 
9 competing bidders;
10   (viii) maintain confidentiality of supplier and 
11 bidding information in a manner consistent with all 
12 applicable laws, rules, regulations, and tariffs;
13   (ix) submit a confidential report to the 
14 Commission recommending acceptance or rejection of 
15 bids;
16   (x) notify the utility of contract counterparties 
17 and contract specifics; and
18   (xi) administer related contingency procurement 
19 events.
20  (2) The procurement monitor, who shall be retained by 
21 the Commission, shall:
22   (i) monitor interactions among the procurement 
23 administrator, suppliers, and utility;
24   (ii) monitor and report to the Commission on the 
25 progress of the procurement process;
26   (iii) provide an independent confidential report 
 
 
SB2552- 135 -LRB103 31416 LNS 59082 b


1 to the Commission regarding the results of the 
2 procurement event;
3   (iv) assess compliance with the procurement plans 
4 approved by the Commission for each utility that on 
5 December 31, 2005 provided electric service to at 
6 least 100,000 customers in Illinois and for each small 
7 multi-jurisdictional utility that on December 31, 2005 
8 served less than 100,000 customers in Illinois;
9   (v) preserve the confidentiality of supplier and 
10 bidding information in a manner consistent with all 
11 applicable laws, rules, regulations, and tariffs;
12   (vi) provide expert advice to the Commission and 
13 consult with the procurement administrator regarding 
14 issues related to procurement process design, rules, 
15 protocols, and policy-related matters; and
16   (vii) consult with the procurement administrator 
17 regarding the development and use of benchmark 
18 criteria, standard form contracts, credit policies, 
19 and bid documents.
20 (d) Except as provided in subsection (j), the planning 
21process shall be conducted as follows:
22  (1) Beginning in 2008, each Illinois utility procuring 
23 power pursuant to this Section shall annually provide a 
24 range of load forecasts to the Illinois Power Agency by 
25 July 15 of each year, or such other date as may be required 
26 by the Commission or Agency. The load forecasts shall 
 
 
SB2552- 136 -LRB103 31416 LNS 59082 b


1 cover the 5-year procurement planning period for the next 
2 procurement plan and shall include hourly data 
3 representing a high-load, low-load, and expected-load 
4 scenario for the load of those retail customers included 
5 in the plan's electric supply service requirements. The 
6 utility shall provide supporting data and assumptions for 
7 each of the scenarios.

8  (2) Beginning in 2008, the Illinois Power Agency shall 
9 prepare a procurement plan by August 15th of each year, or 
10 such other date as may be required by the Commission. The 
11 procurement plan shall identify the portfolio of 
12 demand-response and power and energy products to be 
13 procured. Cost-effective demand-response measures shall be 
14 procured as set forth in item (iii) of subsection (b) of 
15 this Section. Copies of the procurement plan shall be 
16 posted and made publicly available on the Agency's and 
17 Commission's websites, and copies shall also be provided 
18 to each affected electric utility. An affected utility 
19 shall have 30 days following the date of posting to 
20 provide comment to the Agency on the procurement plan. 
21 Other interested entities also may comment on the 
22 procurement plan. All comments submitted to the Agency 
23 shall be specific, supported by data or other detailed 
24 analyses, and, if objecting to all or a portion of the 
25 procurement plan, accompanied by specific alternative 
26 wording or proposals. All comments shall be posted on the 
 
 
SB2552- 137 -LRB103 31416 LNS 59082 b


1 Agency's and Commission's websites. During this 30-day 
2 comment period, the Agency shall hold at least one public 
3 hearing within each utility's service area for the purpose 
4 of receiving public comment on the procurement plan. 
5 Within 14 days following the end of the 30-day review 
6 period, the Agency shall revise the procurement plan as 
7 necessary based on the comments received and file the 
8 procurement plan with the Commission and post the 
9 procurement plan on the websites.
10  (3) Within 5 days after the filing of the procurement 
11 plan, any person objecting to the procurement plan shall 
12 file an objection with the Commission. Within 10 days 
13 after the filing, the Commission shall determine whether a 
14 hearing is necessary. The Commission shall enter its order 
15 confirming or modifying the procurement plan within 90 
16 days after the filing of the procurement plan by the 
17 Illinois Power Agency.
18  (4) The Commission shall approve the procurement plan, 
19 including expressly the forecast used in the procurement 
20 plan, if the Commission determines that it will ensure 
21 adequate, reliable, affordable, efficient, and 
22 environmentally sustainable electric service at the lowest 
23 total cost over time, taking into account any benefits of 
24 price stability.
25  (4.5) The Commission shall review the Agency's 
26 recommendations for the selection of applicants to enter 
 
 
SB2552- 138 -LRB103 31416 LNS 59082 b


1 into long-term contracts for the sale and delivery of 
2 renewable energy credits from new renewable energy 
3 facilities to be constructed at or adjacent to the sites 
4 of coal-fueled electric generating facilities in this 
5 State in accordance with the provisions of subsection 
6 (c-5) of Section 1-75 of the Illinois Power Agency Act, 
7 and shall approve the Agency's recommendations if the 
8 Commission determines that the applicants recommended by 
9 the Agency for selection, the proposed new renewable 
10 energy facilities to be constructed, the amounts of 
11 renewable energy credits to be delivered pursuant to the 
12 contracts, and the other terms of the contracts, are 
13 consistent with the requirements of subsection (c-5) of 
14 Section 1-75 of the Illinois Power Agency Act. 
15 (e) The procurement process shall include each of the 
16following components:
17  (1) Solicitation, pre-qualification, and registration 
18 of bidders. The procurement administrator shall 
19 disseminate information to potential bidders to promote a 
20 procurement event, notify potential bidders that the 
21 procurement administrator may enter into a post-bid price 
22 negotiation with bidders that meet the applicable 
23 benchmarks, provide supply requirements, and otherwise 
24 explain the competitive procurement process. In addition 
25 to such other publication as the procurement administrator 
26 determines is appropriate, this information shall be 
 
 
SB2552- 139 -LRB103 31416 LNS 59082 b


1 posted on the Illinois Power Agency's and the Commission's 
2 websites. The procurement administrator shall also 
3 administer the prequalification process, including 
4 evaluation of credit worthiness, compliance with 
5 procurement rules, and agreement to the standard form 
6 contract developed pursuant to paragraph (2) of this 
7 subsection (e). The procurement administrator shall then 
8 identify and register bidders to participate in the 
9 procurement event.
10  (2) Standard contract forms and credit terms and 
11 instruments. The procurement administrator, in 
12 consultation with the utilities, the Commission, and other 
13 interested parties and subject to Commission oversight, 
14 shall develop and provide standard contract forms for the 
15 supplier contracts that meet generally accepted industry 
16 practices. Standard credit terms and instruments that meet 
17 generally accepted industry practices shall be similarly 
18 developed. The procurement administrator shall make 
19 available to the Commission all written comments it 
20 receives on the contract forms, credit terms, or 
21 instruments. If the procurement administrator cannot reach 
22 agreement with the applicable electric utility as to the 
23 contract terms and conditions, the procurement 
24 administrator must notify the Commission of any disputed 
25 terms and the Commission shall resolve the dispute. The 
26 terms of the contracts shall not be subject to negotiation 
 
 
SB2552- 140 -LRB103 31416 LNS 59082 b


1 by winning bidders, and the bidders must agree to the 
2 terms of the contract in advance so that winning bids are 
3 selected solely on the basis of price.
4  (3) Establishment of a market-based price benchmark. 
5 As part of the development of the procurement process, the 
6 procurement administrator, in consultation with the 
7 Commission staff, Agency staff, and the procurement 
8 monitor, shall establish benchmarks for evaluating the 
9 final prices in the contracts for each of the products 
10 that will be procured through the procurement process. The 
11 benchmarks shall be based on price data for similar 
12 products for the same delivery period and same delivery 
13 hub, or other delivery hubs after adjusting for that 
14 difference. The price benchmarks may also be adjusted to 
15 take into account differences between the information 
16 reflected in the underlying data sources and the specific 
17 products and procurement process being used to procure 
18 power for the Illinois utilities. The benchmarks shall be 
19 confidential but shall be provided to, and will be subject 
20 to Commission review and approval, prior to a procurement 
21 event.
22  (4) Request for proposals competitive procurement 
23 process. The procurement administrator shall design and 
24 issue a request for proposals to supply electricity in 
25 accordance with each utility's procurement plan, as 
26 approved by the Commission. The request for proposals 
 
 
SB2552- 141 -LRB103 31416 LNS 59082 b


1 shall set forth a procedure for sealed, binding commitment 
2 bidding with pay-as-bid settlement, and provision for 
3 selection of bids on the basis of price.
4  (5) A plan for implementing contingencies in the event 
5 of supplier default or failure of the procurement process 
6 to fully meet the expected load requirement due to 
7 insufficient supplier participation, Commission rejection 
8 of results, or any other cause.
9   (i) Event of supplier default: In the event of 
10 supplier default, the utility shall review the 
11 contract of the defaulting supplier to determine if 
12 the amount of supply is 200 megawatts or greater, and 
13 if there are more than 60 days remaining of the 
14 contract term. If both of these conditions are met, 
15 and the default results in termination of the 
16 contract, the utility shall immediately notify the 
17 Illinois Power Agency that a request for proposals 
18 must be issued to procure replacement power, and the 
19 procurement administrator shall run an additional 
20 procurement event. If the contracted supply of the 
21 defaulting supplier is less than 200 megawatts or 
22 there are less than 60 days remaining of the contract 
23 term, the utility shall procure power and energy from 
24 the applicable regional transmission organization 
25 market, including ancillary services, capacity, and 
26 day-ahead or real time energy, or both, for the 
 
 
SB2552- 142 -LRB103 31416 LNS 59082 b


1 duration of the contract term to replace the 
2 contracted supply; provided, however, that if a needed 
3 product is not available through the regional 
4 transmission organization market it shall be purchased 
5 from the wholesale market.
6   (ii) Failure of the procurement process to fully 
7 meet the expected load requirement: If the procurement 
8 process fails to fully meet the expected load 
9 requirement due to insufficient supplier participation 
10 or due to a Commission rejection of the procurement 
11 results, the procurement administrator, the 
12 procurement monitor, and the Commission staff shall 
13 meet within 10 days to analyze potential causes of low 
14 supplier interest or causes for the Commission 
15 decision. If changes are identified that would likely 
16 result in increased supplier participation, or that 
17 would address concerns causing the Commission to 
18 reject the results of the prior procurement event, the 
19 procurement administrator may implement those changes 
20 and rerun the request for proposals process according 
21 to a schedule determined by those parties and 
22 consistent with Section 1-75 of the Illinois Power 
23 Agency Act and this subsection. In any event, a new 
24 request for proposals process shall be implemented by 
25 the procurement administrator within 90 days after the 
26 determination that the procurement process has failed 
 
 
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1 to fully meet the expected load requirement.
2   (iii) In all cases where there is insufficient 
3 supply provided under contracts awarded through the 
4 procurement process to fully meet the electric 
5 utility's load requirement, the utility shall meet the 
6 load requirement by procuring power and energy from 
7 the applicable regional transmission organization 
8 market, including ancillary services, capacity, and 
9 day-ahead or real time energy, or both; provided, 
10 however, that if a needed product is not available 
11 through the regional transmission organization market 
12 it shall be purchased from the wholesale market.
13  (6) The procurement processes described in this 
14 subsection and in subsection (c-5) of Section 1-75 of the 
15 Illinois Power Agency Act are exempt from the requirements 
16 of the Illinois Procurement Code, pursuant to Section 
17 20-10 of that Code.
18 (f) Within 2 business days after opening the sealed bids, 
19the procurement administrator shall submit a confidential 
20report to the Commission. The report shall contain the results 
21of the bidding for each of the products along with the 
22procurement administrator's recommendation for the acceptance 
23and rejection of bids based on the price benchmark criteria 
24and other factors observed in the process. The procurement 
25monitor also shall submit a confidential report to the 
26Commission within 2 business days after opening the sealed 
 
 
SB2552- 144 -LRB103 31416 LNS 59082 b


1bids. The report shall contain the procurement monitor's 
2assessment of bidder behavior in the process as well as an 
3assessment of the procurement administrator's compliance with 
4the procurement process and rules. The Commission shall review 
5the confidential reports submitted by the procurement 
6administrator and procurement monitor, and shall accept or 
7reject the recommendations of the procurement administrator 
8within 2 business days after receipt of the reports.
9 (g) Within 3 business days after the Commission decision 
10approving the results of a procurement event, the utility 
11shall enter into binding contractual arrangements with the 
12winning suppliers using the standard form contracts; except 
13that the utility shall not be required either directly or 
14indirectly to execute the contracts if a tariff that is 
15consistent with subsection (l) of this Section has not been 
16approved and placed into effect for that utility.
17 (h) For the procurement of standard wholesale products, 
18the names of the successful bidders and the load weighted 
19average of the winning bid prices for each contract type and 
20for each contract term shall be made available to the public at 
21the time of Commission approval of a procurement event. For 
22procurements conducted to meet the requirements of subsection 
23(b) of Section 1-56 or subsection (c) of Section 1-75 of the 
24Illinois Power Agency Act governed by the provisions of this 
25Section, the address and nameplate capacity of the new 
26renewable energy generating facility proposed by a winning 
 
 
SB2552- 145 -LRB103 31416 LNS 59082 b


1bidder shall also be made available to the public at the time 
2of Commission approval of a procurement event, along with the 
3business address and contact information for any winning 
4bidder. An estimate or approximation of the nameplate capacity 
5of the new renewable energy generating facility may be 
6disclosed if necessary to protect the confidentiality of 
7individual bid prices.
8 The Commission, the procurement monitor, the procurement 
9administrator, the Illinois Power Agency, and all participants 
10in the procurement process shall maintain the confidentiality 
11of all other supplier and bidding information in a manner 
12consistent with all applicable laws, rules, regulations, and 
13tariffs. Confidential information, including the confidential 
14reports submitted by the procurement administrator and 
15procurement monitor pursuant to subsection (f) of this 
16Section, shall not be made publicly available and shall not be 
17discoverable by any party in any proceeding, absent a 
18compelling demonstration of need, nor shall those reports be 
19admissible in any proceeding other than one for law 
20enforcement purposes.
21 (i) Within 2 business days after a Commission decision 
22approving the results of a procurement event or such other 
23date as may be required by the Commission from time to time, 
24the utility shall file for informational purposes with the 
25Commission its actual or estimated retail supply charges, as 
26applicable, by customer supply group reflecting the costs 
 
 
SB2552- 146 -LRB103 31416 LNS 59082 b


1associated with the procurement and computed in accordance 
2with the tariffs filed pursuant to subsection (l) of this 
3Section and approved by the Commission.
4 (j) Within 60 days following August 28, 2007 (the 
5effective date of Public Act 95-481), each electric utility 
6that on December 31, 2005 provided electric service to at 
7least 100,000 customers in Illinois shall prepare and file 
8with the Commission an initial procurement plan, which shall 
9conform in all material respects to the requirements of the 
10procurement plan set forth in subsection (b); provided, 
11however, that the Illinois Power Agency Act shall not apply to 
12the initial procurement plan prepared pursuant to this 
13subsection. The initial procurement plan shall identify the 
14portfolio of power and energy products to be procured and 
15delivered for the period June 2008 through May 2009, and shall 
16identify the proposed procurement administrator, who shall 
17have the same experience and expertise as is required of a 
18procurement administrator hired pursuant to Section 1-75 of 
19the Illinois Power Agency Act. Copies of the procurement plan 
20shall be posted and made publicly available on the 
21Commission's website. The initial procurement plan may include 
22contracts for renewable resources that extend beyond May 2009.
23  (i) Within 14 days following filing of the initial 
24 procurement plan, any person may file a detailed objection 
25 with the Commission contesting the procurement plan 
26 submitted by the electric utility. All objections to the 
 
 
SB2552- 147 -LRB103 31416 LNS 59082 b


1 electric utility's plan shall be specific, supported by 
2 data or other detailed analyses. The electric utility may 
3 file a response to any objections to its procurement plan 
4 within 7 days after the date objections are due to be 
5 filed. Within 7 days after the date the utility's response 
6 is due, the Commission shall determine whether a hearing 
7 is necessary. If it determines that a hearing is 
8 necessary, it shall require the hearing to be completed 
9 and issue an order on the procurement plan within 60 days 
10 after the filing of the procurement plan by the electric 
11 utility.
12  (ii) The order shall approve or modify the procurement 
13 plan, approve an independent procurement administrator, 
14 and approve or modify the electric utility's tariffs that 
15 are proposed with the initial procurement plan. The 
16 Commission shall approve the procurement plan if the 
17 Commission determines that it will ensure adequate, 
18 reliable, affordable, efficient, and environmentally 
19 sustainable electric service at the lowest total cost over 
20 time, taking into account any benefits of price stability.
21 (k) (Blank).
22 (k-5) (Blank).
23 (l) An electric utility shall recover its costs incurred 
24under this Section and subsection (c-5) of Section 1-75 of the 
25Illinois Power Agency Act, including, but not limited to, the 
26costs of procuring power and energy demand-response resources 
 
 
SB2552- 148 -LRB103 31416 LNS 59082 b


1under this Section and its costs for purchasing renewable 
2energy credits pursuant to subsection (c-5) of Section 1-75 of 
3the Illinois Power Agency Act. The utility shall file with the 
4initial procurement plan its proposed tariffs through which 
5its costs of procuring power that are incurred pursuant to a 
6Commission-approved procurement plan and those other costs 
7identified in this subsection (l), will be recovered. The 
8tariffs shall include a formula rate or charge designed to 
9pass through both the costs incurred by the utility in 
10procuring a supply of electric power and energy for the 
11applicable customer classes with no mark-up or return on the 
12price paid by the utility for that supply, plus any just and 
13reasonable costs that the utility incurs in arranging and 
14providing for the supply of electric power and energy. The 
15formula rate or charge shall also contain provisions that 
16ensure that its application does not result in over or under 
17recovery due to changes in customer usage and demand patterns, 
18and that provide for the correction, on at least an annual 
19basis, of any accounting errors that may occur. A utility 
20shall recover through the tariff all reasonable costs incurred 
21to implement or comply with any procurement plan that is 
22developed and put into effect pursuant to Section 1-75 of the 
23Illinois Power Agency Act and this Section, and for the 
24procurement of renewable energy credits pursuant to subsection 
25(c-5) of Section 1-75 of the Illinois Power Agency Act, 
26including any fees assessed by the Illinois Power Agency, 
 
 
SB2552- 149 -LRB103 31416 LNS 59082 b


1costs associated with load balancing, and contingency plan 
2costs. The electric utility shall also recover its full costs 
3of procuring electric supply for which it contracted before 
4the effective date of this Section in conjunction with the 
5provision of full requirements service under fixed-price 
6bundled service tariffs subsequent to December 31, 2006. All 
7such costs shall be deemed to have been prudently incurred. 
8The pass-through tariffs that are filed and approved pursuant 
9to this Section shall not be subject to review under, or in any 
10way limited by, Section 16-111(i) of this Act. All of the costs 
11incurred by the electric utility associated with the purchase 
12of zero emission credits in accordance with subsection (d-5) 
13of Section 1-75 of the Illinois Power Agency Act, all costs 
14incurred by the electric utility associated with the purchase 
15of carbon mitigation credits in accordance with subsection 
16(d-10) of Section 1-75 of the Illinois Power Agency Act, and, 
17beginning June 1, 2017, all of the costs incurred by the 
18electric utility associated with the purchase of renewable 
19energy resources in accordance with Sections 1-56 and 1-75 of 
20the Illinois Power Agency Act, and all of the costs incurred by 
21the electric utility in purchasing renewable energy credits in 
22accordance with subsection (c-5) of Section 1-75 of the 
23Illinois Power Agency Act, shall be recovered through the 
24electric utility's tariffed charges applicable to all of its 
25retail customers, as specified in subsection (k) or subsection 
26(i-5), as applicable, of Section 16-108 of this Act, and shall 
 
 
SB2552- 150 -LRB103 31416 LNS 59082 b


1not be recovered through the electric utility's tariffed 
2charges for electric power and energy supply to its eligible 
3retail customers.
4 (m) The Commission has the authority to adopt rules to 
5carry out the provisions of this Section. For the public 
6interest, safety, and welfare, the Commission also has 
7authority to adopt rules to carry out the provisions of this 
8Section on an emergency basis immediately following August 28, 
92007 (the effective date of Public Act 95-481).
10 (n) Notwithstanding any other provision of this Act, any 
11affiliated electric utilities that submit a single procurement 
12plan covering their combined needs may procure for those 
13combined needs in conjunction with that plan, and may enter 
14jointly into power supply contracts, purchases, and other 
15procurement arrangements, and allocate capacity and energy and 
16cost responsibility therefor among themselves in proportion to 
17their requirements.
18 (o) On or before June 1 of each year, the Commission shall 
19hold an informal hearing for the purpose of receiving comments 
20on the prior year's procurement process and any 
21recommendations for change.

22 (p) An electric utility subject to this Section may 
23propose to invest, lease, own, or operate an electric 
24generation facility as part of its procurement plan, provided 
25the utility demonstrates that such facility is the least-cost 
26option to provide electric service to those retail customers 
 
 
SB2552- 151 -LRB103 31416 LNS 59082 b


1included in the plan's electric supply service requirements. 
2If the facility is shown to be the least-cost option and is 
3included in a procurement plan prepared in accordance with 
4Section 1-75 of the Illinois Power Agency Act and this 
5Section, then the electric utility shall make a filing 
6pursuant to Section 8-406 of this Act, and may request of the 
7Commission any statutory relief required thereunder. If the 
8Commission grants all of the necessary approvals for the 
9proposed facility, such supply shall thereafter be considered 
10as a pre-existing contract under subsection (b) of this 
11Section. The Commission shall in any order approving a 
12proposal under this subsection specify how the utility will 
13recover the prudently incurred costs of investing in, leasing, 
14owning, or operating such generation facility through just and 
15reasonable rates charged to those retail customers included in 
16the plan's electric supply service requirements. Cost recovery 
17for facilities included in the utility's procurement plan 
18pursuant to this subsection shall not be subject to review 
19under or in any way limited by the provisions of Section 
2016-111(i) of this Act. Nothing in this Section is intended to 
21prohibit a utility from filing for a fuel adjustment clause as 
22is otherwise permitted under Section 9-220 of this Act.


23 (q) If the Illinois Power Agency filed with the 
24Commission, under Section 16-111.5 of this Act, its proposed 
25procurement plan for the period commencing June 1, 2017, and 
26the Commission has not yet entered its final order approving 
 
 
SB2552- 152 -LRB103 31416 LNS 59082 b


1the plan on or before the effective date of this amendatory Act 
2of the 99th General Assembly, then the Illinois Power Agency 
3shall file a notice of withdrawal with the Commission, after 
4the effective date of this amendatory Act of the 99th General 
5Assembly, to withdraw the proposed procurement of renewable 
6energy resources to be approved under the plan, other than the 
7procurement of renewable energy credits from distributed 
8renewable energy generation devices using funds previously 
9collected from electric utilities' retail customers that take 
10service pursuant to electric utilities' hourly pricing tariff 
11or tariffs and, for an electric utility that serves less than 
12100,000 retail customers in the State, other than the 
13procurement of renewable energy credits from distributed 
14renewable energy generation devices. Upon receipt of the 
15notice, the Commission shall enter an order that approves the 
16withdrawal of the proposed procurement of renewable energy 
17resources from the plan. The initially proposed procurement of 
18renewable energy resources shall not be approved or be the 
19subject of any further hearing, investigation, proceeding, or 
20order of any kind.
21 This amendatory Act of the 99th General Assembly preempts 
22and supersedes any order entered by the Commission that 
23approved the Illinois Power Agency's procurement plan for the 
24period commencing June 1, 2017, to the extent it is 
25inconsistent with the provisions of this amendatory Act of the 
2699th General Assembly. To the extent any previously entered 
 
 
SB2552- 153 -LRB103 31416 LNS 59082 b


1order approved the procurement of renewable energy resources, 
2the portion of that order approving the procurement shall be 
3void, other than the procurement of renewable energy credits 
4from distributed renewable energy generation devices using 
5funds previously collected from electric utilities' retail 
6customers that take service under electric utilities' hourly 
7pricing tariff or tariffs and, for an electric utility that 
8serves less than 100,000 retail customers in the State, other 
9than the procurement of renewable energy credits for 
10distributed renewable energy generation devices. 
11(Source: P.A. 102-662, eff. 9-15-21.)



12 (220 ILCS 5/16-115)


13 Sec. 16-115. Certification of alternative retail
electric 
14suppliers.
15 (a) Any alternative retail electric supplier must obtain
a 
16certificate of service authority from the Commission in

17accordance with this Section before serving any retail

18customer or other user located in this State. An alternative

19retail electric supplier may request, and the Commission may

20grant, a certificate of service authority for the entire State

21or for a specified geographic area of the State. A certificate 
22granted pursuant to this Section is not property, and the 
23grant of a certificate to an entity does not create a property 
24interest in the certificate. This Section does not diminish 
25the existing rights of a certificate holder to notice and 
 
 
SB2552- 154 -LRB103 31416 LNS 59082 b


1hearing as proscribed by the Illinois Administrative Procedure 
2Act and in rules adopted by the Commission. 

3 (b) An alternative retail electric supplier seeking a

4certificate of service authority shall file with the

5Commission a verified application containing information

6showing that the applicant meets the requirements of this

7Section. The alternative retail electric supplier shall

8publish notice of its application in the official State

9newspaper within 10 days following the date of its filing. No

10later than 45 days after a complete application is properly 
11filed
with the Commission, and such notice is published, the

12Commission shall issue its order granting or denying the

13application.

14 (c) An application for a certificate of service
authority 
15shall identify the area or areas in which the
applicant 
16intends to offer service and the types of services
it intends 
17to offer. Applicants that seek to serve
residential or small 
18commercial retail customers within a
geographic area that is 
19smaller than an electric utility's
service area shall submit 
20evidence demonstrating that the
designation of this smaller 
21area does not violate Section 16-115A. An applicant
that seeks 
22to serve residential or small
commercial retail customers may 
23state in its application for
certification any limitations 
24that will be imposed on the
number of customers or maximum load 
25to be served.

26 (d) The Commission shall grant the application for a

 
 
SB2552- 155 -LRB103 31416 LNS 59082 b


1certificate of service authority if it makes the findings set

2forth in this subsection
based on the verified
application and 
3such other information as the applicant may
submit:

4  (1) That the applicant possesses sufficient
technical, 
5 financial, and managerial resources and
abilities to 
6 provide the service for which it seeks a
certificate of 
7 service authority. In determining the
level of technical, 
8 financial, and managerial resources
and abilities which 
9 the applicant must demonstrate, the
Commission shall 
10 consider (i) the characteristics,
including the size and 
11 financial sophistication, of the
customers that the 
12 applicant seeks to serve, and (ii)
whether the applicant 
13 seeks to provide electric power and
energy using property, 
14 plant, and equipment which it owns,
controls, or operates;

15  (2) That the applicant will comply with all
applicable 
16 federal, State, regional, and industry rules,
policies, 
17 practices, and procedures for the use,
operation, and 
18 maintenance of the safety, integrity, and
reliability, of 
19 the interconnected electric transmission
system;

20  (3) That the applicant will only provide service to

21 retail customers in an electric utility's service area

22 that are eligible to take delivery services under this

23 Act;

24  (4) That the applicant will comply with such

25 informational or reporting requirements as the Commission

26 may by rule establish and provide the information required 
 
 
SB2552- 156 -LRB103 31416 LNS 59082 b


1 by Section 16-112.
Any data related to
contracts for the 
2 purchase and sale of electric power and
energy shall be 
3 made available for review by the Staff of
the Commission 
4 on a confidential and proprietary basis
and only to the 
5 extent and for the purposes which the
Commission 
6 determines are reasonably necessary in order
to carry out 
7 the purposes of this Act;

8  (5) That the applicant will procure renewable energy 
9 resources and comply with the capacity portfolio 
10 requirement in accordance with Section 16-115D of this 
11 Act, and will source electricity from clean coal 
12 facilities, as defined in Section 1-10 of the Illinois 
13 Power Agency Act, in amounts at least equal to the 
14 percentages set forth in subsections (c) and (d) of 
15 Section 1-75 of the Illinois Power Agency Act. For 
16 purposes of this Section: 

17   (i) (blank);
18   (ii) (blank);
19   (iii) the required sourcing of electricity 
20 generated by clean coal facilities, other than the 
21 initial clean coal facility, shall be limited to the 
22 amount of electricity that can be procured or sourced 
23 at a price at or below the benchmarks approved by the 
24 Commission each year in accordance with item (1) of 
25 subsection (c) and items (1) and (5) of subsection (d) 
26 of Section 1-75 of the Illinois Power Agency Act;
 
 
SB2552- 157 -LRB103 31416 LNS 59082 b


1   (iv) all alternative retail electric suppliers 
2 shall execute a sourcing agreement to source 
3 electricity from the initial clean coal facility, on 
4 the terms set forth in paragraphs (3) and (4) of 
5 subsection (d) of Section 1-75 of the Illinois Power 
6 Agency Act, except that in lieu of the requirements in 
7 subparagraphs (A)(v), (B)(i), (C)(v), and (C)(vi) of 
8 paragraph (3) of that subsection (d), the applicant 
9 shall execute one or more of the following:
10    (1) if the sourcing agreement is a power 
11 purchase agreement, a contract with the initial 
12 clean coal facility to purchase in each hour an 
13 amount of electricity equal to all clean coal 
14 energy made available from the initial clean coal 
15 facility during such hour, which the utilities are 
16 not required to procure under the terms of 
17 subsection (d) of Section 1-75 of the Illinois 
18 Power Agency Act, multiplied by a fraction, the 
19 numerator of which is the alternative retail 
20 electric supplier's retail market sales of 
21 electricity (expressed in kilowatthours sold) in 
22 the State during the prior calendar month and the 
23 denominator of which is the total sales of 
24 electricity (expressed in kilowatthours sold) in 
25 the State by alternative retail electric suppliers 
26 during such prior month that are subject to the 
 
 
SB2552- 158 -LRB103 31416 LNS 59082 b


1 requirements of this paragraph (5) of subsection 
2 (d) of this Section and subsection (d) of Section 
3 1-75 of the Illinois Power Agency Act plus the 
4 total sales of electricity (expressed in 
5 kilowatthours sold) by utilities outside of their 
6 service areas during such prior month, pursuant to 
7 subsection (c) of Section 16-116 of this Act; or
8    (2) if the sourcing agreement is a contract 
9 for differences, a contract with the initial clean 
10 coal facility in each hour with respect to an 
11 amount of electricity equal to all clean coal 
12 energy made available from the initial clean coal 
13 facility during such hour, which the utilities are 
14 not required to procure under the terms of 
15 subsection (d) of Section 1-75 of the Illinois 
16 Power Agency Act, multiplied by a fraction, the 
17 numerator of which is the alternative retail 
18 electric supplier's retail market sales of 
19 electricity (expressed in kilowatthours sold) in 
20 the State during the prior calendar month and the 
21 denominator of which is the total sales of 
22 electricity (expressed in kilowatthours sold) in 
23 the State by alternative retail electric suppliers 
24 during such prior month that are subject to the 
25 requirements of this paragraph (5) of subsection 
26 (d) of this Section and subsection (d) of Section 
 
 
SB2552- 159 -LRB103 31416 LNS 59082 b


1 1-75 of the Illinois Power Agency Act plus the 
2 total sales of electricity (expressed in 
3 kilowatthours sold) by utilities outside of their 
4 service areas during such prior month, pursuant to 
5 subsection (c) of Section 16-116 of this Act; 
6   (v) if, in any year after the first year of 
7 commercial operation, the owner of the clean coal 
8 facility fails to demonstrate to the Commission that 
9 the initial clean coal facility captured and 
10 sequestered at least 50% of the total carbon emissions 
11 that the facility would otherwise emit or that 
12 sequestration of emissions from prior years has 
13 failed, resulting in the release of carbon into the 
14 atmosphere, the owner of the facility must offset 
15 excess emissions. Any such carbon offsets must be 
16 permanent, additional, verifiable, real, located 
17 within the State of Illinois, and legally and 
18 practicably enforceable. The costs of any such offsets 
19 that are not recoverable shall not exceed $15,000,000 
20 in any given year. No costs of any such purchases of 
21 carbon offsets may be recovered from an alternative 
22 retail electric supplier or its customers. All carbon 
23 offsets purchased for this purpose and any carbon 
24 emission credits associated with sequestration of 
25 carbon from the facility must be permanently retired. 
26 The initial clean coal facility shall not forfeit its 
 
 
SB2552- 160 -LRB103 31416 LNS 59082 b


1 designation as a clean coal facility if the facility 
2 fails to fully comply with the applicable carbon 
3 sequestration requirements in any given year, provided 
4 the requisite offsets are purchased. However, the 
5 Attorney General, on behalf of the People of the State 
6 of Illinois, may specifically enforce the facility's 
7 sequestration requirement and the other terms of this 
8 contract provision. Compliance with the sequestration 
9 requirements and offset purchase requirements that 
10 apply to the initial clean coal facility shall be 
11 reviewed annually by an independent expert retained by 
12 the owner of the initial clean coal facility, with the 
13 advance written approval of the Attorney General;
14   (vi) The Commission shall, after notice and 
15 hearing, revoke the certification of any alternative 
16 retail electric supplier that fails to execute a 
17 sourcing agreement with the initial clean coal 
18 facility as required by item (5) of subsection (d) of 
19 this Section. The sourcing agreements with this 
20 initial clean coal facility shall be subject to both 
21 approval of the initial clean coal facility by the 
22 General Assembly and satisfaction of the requirements 
23 of item (4) of subsection (d) of Section 1-75 of the 
24 Illinois Power Agency Act, and shall be executed 
25 within 90 days after any such approval by the General 
26 Assembly. The Commission shall not accept an 
 
 
SB2552- 161 -LRB103 31416 LNS 59082 b


1 application for certification from an alternative 
2 retail electric supplier that has lost certification 
3 under this subsection (d), or any corporate affiliate 
4 thereof, for at least one year from the date of 
5 revocation; 
6  (6) With respect to an applicant that seeks to serve

7 residential or small commercial retail customers, that
the 
8 area to be served by the applicant and any
limitations it 
9 proposes on the number of customers or
maximum amount of 
10 load to be served meet the provisions
of Section 16-115A, 
11 provided, that the Commission can
extend the time for 
12 considering such a certificate
request by up to 90 days, 
13 and can schedule hearings on
such a request;

14  (7) That the applicant meets the requirements of 
15 subsection (a) of Section
16-128;

16  (8) That the applicant discloses whether the applicant 
17 is the subject of any lawsuit filed in a court of law or 
18 formal complaint filed with a regulatory agency alleging 
19 fraud, deception, or unfair marketing practices or other 
20 similar allegations and, if the applicant is the subject 
21 of such lawsuit or formal complaint, the applicant shall 
22 identify the name, case number, and jurisdiction of each 
23 lawsuit or complaint, and that the applicant is capable of 
24 fulfilling its obligations as an alternative retail 
25 electric supplier in Illinois notwithstanding any lawsuit 
26 or complaint. For the purpose of this item (8), "formal 
 
 
SB2552- 162 -LRB103 31416 LNS 59082 b


1 complaint" includes only those complaints that seek a 
2 binding determination from a State or federal regulatory 
3 body;
4  (9) That the applicant shall at all times remain in 
5 compliance with requirements for certification stated in 
6 this Section and as the Commission may establish by rule;
7  (10) That the applicant shall execute and maintain a 
8 license or permit bond issued by a qualifying surety or 
9 insurance company authorized to transact business in the 
10 State of Illinois in favor of the People of the State of 
11 Illinois. The amount of the bond shall equal $30,000 if 
12 the applicant seeks to serve only nonresidential retail 
13 customers with maximum electrical demands of one megawatt 
14 or more, $150,000 if the applicant seeks to serve only 
15 nonresidential retail customers with annual electrical 
16 consumption greater than 15,000 kilowatt-hours, or 
17 $500,000 if the applicant seeks to serve all eligible 
18 customers. Applicants shall be required to submit an 
19 additional $500,000 bond if the applicant intends to 
20 market to residential customers using in-person 
21 solicitations. The bonds shall be conditioned upon the 
22 full and faithful performance of all duties and 
23 obligations of the applicant as an alternative retail 
24 electric supplier, shall be valid for a period of not less 
25 than one year, and may be drawn upon in whole or in part to 
26 satisfy any penalties imposed, and finally adjudicated, by 
 
 
SB2552- 163 -LRB103 31416 LNS 59082 b


1 the Commission pursuant to Section 16-115B for a violation 
2 of the applicant's duties or obligations, except that the 
3 total amount of claims and penalties against the bond 
4 shall not exceed the penal sum of the bond and shall not 
5 include any consequential or punitive damage. The cost of 
6 the bond shall be paid by the applicant. The applicant 
7 shall file a copy of this bond, with a notarized 
8 verification page from the issuer, as part of its 
9 application for certification under 83 Ill. Adm. Code 451; 
10 and
11  (11) That the applicant will comply with all other

12 applicable laws and regulations.

13 (d-3) The Commission may deny with prejudice an 
14application in which the applicant fails to provide the 
15Commission with information sufficient for the Commission to 
16grant the application. 
17 (d-5) (Blank). 
18 (e) A retail customer that owns a cogeneration or 
19self-generation facility
and that seeks certification only to

20provide electric power and energy from such facility to
retail 
21customers at separate locations which customers are
both (i) 
22owned by, or a subsidiary or other corporate
affiliate of, 
23such applicant and
(ii) eligible for delivery services, shall 
24be granted a
certificate of service authority upon filing an 
25application
and notifying the Commission that it has entered 
26into an
agreement with the relevant electric utilities 
 
 
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1pursuant to
Section 16-118.
Provided, however, that if the 
2retail customer owning such cogeneration or
self-generation 
3facility would not be charged a transition charge due to the

4exemption provided under subsection (f) of Section 16-108 
5prior to the
certification, and the retail customers at 
6separate locations are taking
delivery services in conjunction 
7with purchasing power and energy from the
facility, the retail 
8customer on whose premises the facility is located shall
not 
9thereafter be required to pay transition charges on the power 
10and energy
that such retail customer takes from the facility.

11 (f) The Commission shall have the authority to
promulgate 
12rules and regulations to carry out the provisions
of this 
13Section. On or before May 1, 1999, the Commission
shall adopt a 
14rule or rules applicable to the certification of
those 
15alternative retail electric suppliers that seek to serve
only 
16nonresidential retail customers with maximum electrical

17demands of one megawatt or more which shall provide for (i)

18expedited and streamlined procedures
for certification of such 
19alternative
retail electric suppliers and (ii) specific 
20criteria which,
if met by any such alternative retail electric 
21supplier, shall
constitute the demonstration of technical, 
22financial and
managerial resources and abilities to provide 
23service required
by paragraph (1) of subsection (d) of this 
24Section, such as a requirement
to post a bond or letter of 
25credit, from a responsible surety
or financial institution, of 
26sufficient size for the nature
and scope of the services to be 
 
 
SB2552- 165 -LRB103 31416 LNS 59082 b


1provided; demonstration of
adequate insurance for the scope 
2and nature of the services to
be provided; and experience in 
3providing similar services in
other jurisdictions.

4 (g) An alternative retail electric supplier may seek 
5confidential treatment for the following information by filing 
6an affidavit with the Commission so long as the affidavit 
7meets the requirements in this subsection (g):
8  (1) the total annual kilowatt-hours delivered and sold 
9 by an alternative retail electric supplier to retail 
10 customers within each utility service territory and the 
11 total annual kilowatt-hours delivered and sold by an 
12 alternative retail electric supplier to retail customers 
13 in all utility service territories in the preceding 
14 calendar year as required by 83 Ill. Adm. Code 451.770;
15  (2) the total peak demand supplied by an alternative 
16 retail electric supplier during the previous year in each 
17 utility service territory as required by 83 Ill. Adm. Code 
18 465.40;
19  (3) a good faith estimate of the amount an alternative 
20 retail electric supplier expects to be obliged to pay the 
21 utility under single billing tariffs during the next 12 
22 months and the amount of any bond or letter of credit used 
23 to demonstrate an alternative retail electric supplier's 
24 credit worthiness to provide single billing services 
25 pursuant to 83 Ill. Adm. Code 451.510(a) and (b).
26 The affidavit must be filed contemporaneously with the 
 
 
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1information for which confidential treatment is sought and 
2must clearly state that the affiant seeks confidential 
3treatment pursuant to this subsection (g) and the information 
4for which confidential treatment is sought must be clearly 
5identified on the confidential version of the document filed 
6with the Commission. The affidavit must be accompanied by a 
7"confidential" and a "public" version of the document or 
8documents containing the information for which confidential 
9treatment is sought.
10 If the alternative retail electric supplier has met the 
11affidavit requirements of this subsection (g), then the 
12Commission shall afford confidential treatment to the 
13information identified in the affidavit for a period of 2 
14years after the date the affidavit is received by the 
15Commission.
16 Nothing in this subsection (g) prevents an alternative 
17retail electric supplier from filing a petition with the 
18Commission seeking confidential treatment for information 
19beyond that identified in this subsection (g) or for 
20information contained in other reports or documents filed with 
21the Commission other than annual rate reports.
22 Nothing in this subsection (g) prevents the Commission, on 
23its own motion, or any party from filing a formal petition with 
24the Commission seeking to reconsider the conferring of 
25confidential status on an item of information afforded 
26confidential treatment pursuant to this subsection (g).
 
 
SB2552- 167 -LRB103 31416 LNS 59082 b


1 The Commission, on its own motion, may at any time 
2initiate a docketed proceeding to investigate the continued 
3applicability of this subsection (g) to the information 
4contained in items (i), (ii), and (iii) of this subsection 
5(g). If, at the end of such investigation, the Commission 
6determines that a particular item of information should no 
7longer be eligible for the affidavit-based process outlined in 
8this subsection (g), the Commission may enter an order to 
9remove that item from the list of items eligible for the 
10process set forth in this subsection (g). Notwithstanding any 
11such order, in the event the Commission makes such a 
12determination, nothing in this subsection (g) prevents an 
13alternative retail electric supplier desiring confidential 
14treatment for such information from filing a formal petition 
15with the Commission seeking confidential treatment for such 
16information.
17(Source: P.A. 101-590, eff. 1-1-20; 102-958, eff. 1-1-23.)


18 (220 ILCS 5/16-115D)
19 Sec. 16-115D. Renewable portfolio standard for alternative 
20retail electric suppliers and electric utilities operating 
21outside their service territories.
22 (a) An alternative retail electric supplier shall be 
23responsible for procuring cost-effective renewable energy 
24resources as required under item (5) of subsection (d) of 
25Section 16-115 of this Act as outlined herein:
 
 
SB2552- 168 -LRB103 31416 LNS 59082 b


1  (1) The definition of renewable energy resources 
2 contained in Section 1-10 of the Illinois Power Agency Act 
3 applies to all renewable energy resources required to be 
4 procured by alternative retail electric suppliers.
5  (2) Through May 31, 2017, the quantity of renewable 
6 energy resources shall be measured as a percentage of the 
7 actual amount of metered electricity (megawatt-hours) 
8 delivered by the alternative retail electric supplier to 
9 Illinois retail customers during the 12-month period June 
10 1 through May 31, commencing June 1, 2009, and the 
11 comparable 12-month period in each year thereafter except 
12 as provided in item (6) of this subsection (a). 
13  (3) Through May 31, 2017, the quantity of renewable 
14 energy resources shall be in amounts at least equal to the 
15 annual percentages set forth in item (1) of subsection (c) 
16 of Section 1-75 of the Illinois Power Agency Act. At least 
17 60% of the renewable energy resources procured pursuant to 
18 items (1) and (3) of subsection (b) of this Section shall 
19 come from wind generation and, starting June 1, 2015, at 
20 least 6% of the renewable energy resources procured 
21 pursuant to items (1) and (3) of subsection (b) of this 
22 Section shall come from solar photovoltaics. If, in any 
23 given year, an alternative retail electric supplier does 
24 not purchase at least these levels of renewable energy 
25 resources, then the alternative retail electric supplier 
26 shall make alternative compliance payments, as described 
 
 
SB2552- 169 -LRB103 31416 LNS 59082 b


1 in subsection (d) of this Section.
2  (3.5) For the delivery year commencing June 1, 2017, 
3 the quantity of renewable energy resources shall be at 
4 least 13.0% of the uncovered amount of metered electricity 
5 (megawatt-hours) delivered by the alternative retail 
6 electric supplier to Illinois retail customers during the 
7 delivery year, which uncovered amount shall equal 50% of 
8 such metered electricity delivered by the alternative 
9 retail electric supplier. For the delivery year commencing 
10 June 1, 2018, the quantity of renewable energy resources 
11 shall be at least 14.5% of the uncovered amount of metered 
12 electricity (megawatt-hours) delivered by the alternative 
13 retail electric supplier to Illinois retail customers 
14 during the delivery year, which uncovered amount shall 
15 equal 25% of such metered electricity delivered by the 
16 alternative retail electric supplier. At least 32% of the 
17 renewable energy resources procured by the alternative 
18 retail electric supplier for its uncovered portion under 
19 this paragraph (3.5) shall come from wind or photovoltaic 
20 generation. The renewable energy resources procured under 
21 this paragraph (3.5) shall not include any resources from 
22 a facility whose costs were being recovered through rates 
23 regulated by any state or states on or after January 1, 
24 2017. 
25  (4) The quantity and source of renewable energy 
26 resources shall be independently verified through the PJM 
 
 
SB2552- 170 -LRB103 31416 LNS 59082 b


1 Environmental Information System Generation Attribute 
2 Tracking System (PJM-GATS) or the Midwest Renewable Energy 
3 Tracking System (M-RETS), which shall document the 
4 location of generation, resource type, month, and year of 
5 generation for all qualifying renewable energy resources 
6 that an alternative retail electric supplier uses to 
7 comply with this Section. No later than June 1, 2009, the 
8 Illinois Power Agency shall provide PJM-GATS, M-RETS, and 
9 alternative retail electric suppliers with all information 
10 necessary to identify resources located in Illinois, 
11 within states that adjoin Illinois or within portions of 
12 the PJM and MISO footprint in the United States that 
13 qualify under the definition of renewable energy resources 
14 in Section 1-10 of the Illinois Power Agency Act for 
15 compliance with this Section 16-115D. Alternative retail 
16 electric suppliers shall not be subject to the 
17 requirements in item (3) of subsection (c) of Section 1-75 
18 of the Illinois Power Agency Act.
19  (5) All renewable energy credits used to comply with 
20 this Section shall be permanently retired.
21  (6) The required procurement of renewable energy 
22 resources by an alternative retail electric supplier shall 
23 apply to all metered electricity delivered to Illinois 
24 retail customers by the alternative retail electric 
25 supplier pursuant to contracts executed or extended after 
26 March 15, 2009.
 
 
SB2552- 171 -LRB103 31416 LNS 59082 b


1 (b) Compliance obligations.
2  (1) Through May 31, 2017, an alternative retail 
3 electric supplier shall comply with the renewable energy 
4 portfolio standards by making an alternative compliance 
5 payment, as described in subsection (d) of this Section, 
6 to cover at least one-half of the alternative retail 
7 electric supplier's compliance obligation for the period 
8 prior to June 1, 2017.
9  (2) For the delivery years beginning June 1, 2017 and 
10 June 1, 2018, an alternative retail electric supplier need 
11 not make any alternative compliance payment to meet any 
12 portion of its compliance obligation, as set forth in 
13 paragraph (3.5) of subsection (a) of this Section.
14  (3) An alternative retail electric supplier shall use 
15 any one or combination of the following means to cover the 
16 remainder of the alternative retail electric supplier's 
17 compliance obligation, as set forth in paragraphs (3) and 
18 (3.5) of subsection (a) of this Section, not covered by an 
19 alternative compliance payment made under paragraphs (1) 
20 and (2) of this subsection (b) of this Section:
21   (A) Generating electricity using renewable energy 
22 resources identified pursuant to item (4) of 
23 subsection (a) of this Section.
24   (B) Purchasing electricity generated using 
25 renewable energy resources identified pursuant to item 
26 (4) of subsection (a) of this Section through an 
 
 
SB2552- 172 -LRB103 31416 LNS 59082 b


1 energy contract.
2   (C) Purchasing renewable energy credits from 
3 renewable energy resources identified pursuant to item 
4 (4) of subsection (a) of this Section.
5   (D) Making an alternative compliance payment as 
6 described in subsection (d) of this Section.
7 (c) Use of renewable energy credits.
8  (1) Renewable energy credits that are not used by an 
9 alternative retail electric supplier to comply with a 
10 renewable portfolio standard in a compliance year may be 
11 banked and carried forward up to 2 12-month compliance 
12 periods after the compliance period in which the credit 
13 was generated for the purpose of complying with a 
14 renewable portfolio standard in those 2 subsequent 
15 compliance periods. For the 2009-2010 and 2010-2011 
16 compliance periods, an alternative retail electric 
17 supplier may use renewable credits generated after 
18 December 31, 2008 and before June 1, 2009 to comply with 
19 this Section.
20  (2) An alternative retail electric supplier is 
21 responsible for demonstrating that a renewable energy 
22 credit used to comply with a renewable portfolio standard 
23 is derived from a renewable energy resource and that the 
24 alternative retail electric supplier has not used, traded, 
25 sold, or otherwise transferred the credit.
26  (3) The same renewable energy credit may be used by an 
 
 
SB2552- 173 -LRB103 31416 LNS 59082 b


1 alternative retail electric supplier to comply with a 
2 federal renewable portfolio standard and a renewable 
3 portfolio standard established under this Act. An 
4 alternative retail electric supplier that uses a renewable 
5 energy credit to comply with a renewable portfolio 
6 standard imposed by any other state may not use the same 
7 credit to comply with a renewable portfolio standard 
8 established under this Act.
9 (d) Alternative compliance payments.
10  (1) The Commission shall establish and post on its 
11 website, within 5 business days after entering an order 
12 approving a procurement plan pursuant to Section 1-75 of 
13 the Illinois Power Agency Act, maximum alternative 
14 compliance payment rates, expressed on a per kilowatt-hour 
15 basis, that will be applicable in the first compliance 
16 period following the plan approval. A separate maximum 
17 alternative compliance payment rate shall be established 
18 for the service territory of each electric utility that is 
19 subject to subsection (c) of Section 1-75 of the Illinois 
20 Power Agency Act. Each maximum alternative compliance 
21 payment rate shall be equal to the maximum allowable 
22 annual estimated average net increase due to the costs of 
23 the utility's purchase of renewable energy resources 
24 included in the amounts paid by eligible retail customers 
25 in connection with electric service, as described in item 
26 (2) of subsection (c) of Section 1-75 of the Illinois 
 
 
SB2552- 174 -LRB103 31416 LNS 59082 b


1 Power Agency Act for the compliance period, and as 
2 established in the approved procurement plan. Following 
3 each procurement event through which renewable energy 
4 resources are purchased for one or more of these utilities 
5 for the compliance period, the Commission shall establish 
6 and post on its website estimates of the alternative 
7 compliance payment rates, expressed on a per kilowatt-hour 
8 basis, that shall apply for that compliance period. 
9 Posting of the estimates shall occur no later than 10 
10 business days following the procurement event, however, 
11 the Commission shall not be required to establish and post 
12 such estimates more often than once per calendar month. By 
13 July 1 of each year, the Commission shall establish and 
14 post on its website the actual alternative compliance 
15 payment rates for the preceding compliance year. For 
16 compliance years beginning prior to June 1, 2014, each 
17 alternative compliance payment rate shall be equal to the 
18 total amount of dollars that the utility contracted to 
19 spend on renewable resources, excepting the additional 
20 incremental cost attributable to solar resources, for the 
21 compliance period divided by the forecasted load of 
22 eligible retail customers, at the customers' meters, as 
23 previously established in the Commission-approved 
24 procurement plan for that compliance year. For compliance 
25 years commencing on or after June 1, 2014, each 
26 alternative compliance payment rate shall be equal to the 
 
 
SB2552- 175 -LRB103 31416 LNS 59082 b


1 total amount of dollars that the utility contracted to 
2 spend on all renewable resources for the compliance period 
3 divided by the forecasted load of retail customers for 
4 which the utility is procuring renewable energy resources 
5 in a given delivery year, at the customers' meters, as 
6 previously established in the Commission-approved 
7 procurement plan for that compliance year. The actual 
8 alternative compliance payment rates may not exceed the 
9 maximum alternative compliance payment rates established 
10 for the compliance period. For purposes of this subsection 
11 (d), the term "eligible retail customers" has the same 
12 meaning as found in Section 16-111.5 of this Act.
13  (2) In any given compliance year, an alternative 
14 retail electric supplier may elect to use alternative 
15 compliance payments to comply with all or a part of the 
16 applicable renewable portfolio standard. In the event that 
17 an alternative retail electric supplier elects to make 
18 alternative compliance payments to comply with all or a 
19 part of the applicable renewable portfolio standard, such 
20 payments shall be made by September 1, 2010 for the period 
21 of June 1, 2009 to May 1, 2010 and by September 1 of each 
22 year thereafter for the subsequent compliance period, in 
23 the manner and form as determined by the Commission. Any 
24 election by an alternative retail electric supplier to use 
25 alternative compliance payments is subject to review by 
26 the Commission under subsection (e) of this Section.
 
 
SB2552- 176 -LRB103 31416 LNS 59082 b


1  (3) An alternative retail electric supplier's 
2 alternative compliance payments shall be computed 
3 separately for each electric utility's service territory 
4 within which the alternative retail electric supplier 
5 provided retail service during the compliance period, 
6 provided that the electric utility was subject to 
7 subsection (c) of Section 1-75 of the Illinois Power 
8 Agency Act. For each service territory, the alternative 
9 retail electric supplier's alternative compliance payment 
10 shall be equal to (i) the actual alternative compliance 
11 payment rate established in item (1) of this subsection 
12 (d), multiplied by (ii) the actual amount of metered 
13 electricity delivered by the alternative retail electric 
14 supplier to retail customers for which the supplier has a 
15 compliance obligation within the service territory during 
16 the compliance period, multiplied by (iii) the result of 
17 one minus the ratios of the quantity of renewable energy 
18 resources used by the alternative retail electric supplier 
19 to comply with the requirements of this Section within the 
20 service territory to the product of the percentage of 
21 renewable energy resources required under item (3) or 
22 (3.5) of subsection (a) of this Section and the actual 
23 amount of metered electricity delivered by the alternative 
24 retail electrical supplier to retail customers for which 
25 the supplier has a compliance obligation within the 
26 service territory during the compliance period.
 
 
SB2552- 177 -LRB103 31416 LNS 59082 b


1  (4) Through May 31, 2017, all alternative compliance 
2 payments by alternative retail electric suppliers shall be 
3 deposited in the Illinois Power Agency Renewable Energy 
4 Resources Fund and used to purchase renewable energy 
5 credits, in accordance with Section 1-56 of the Illinois 
6 Power Agency Act. Beginning April 1, 2012 and by April 1 of 
7 each year thereafter, the Illinois Power Agency shall 
8 submit an annual report to the General Assembly, the 
9 Commission, and alternative retail electric suppliers that 
10 shall include, but not be limited to:
11   (A) the total amount of alternative compliance 
12 payments received in aggregate from alternative retail 
13 electric suppliers by planning year for all previous 
14 planning years in which the alternative compliance 
15 payment was in effect;
16   (B) the amount of those payments utilized to 
17 purchased renewable energy credits itemized by the 
18 date of each procurement in which the payments were 
19 utilized; and
20   (C) the unused and remaining balance in the Agency 
21 Renewable Energy Resources Fund attributable to those 
22 payments. 
23  (4.5) Beginning with the delivery year commencing June 
24 1, 2017, all alternative compliance payments by 
25 alternative retail electric suppliers shall be remitted to 
26 the applicable electric utility. To facilitate this 
 
 
SB2552- 178 -LRB103 31416 LNS 59082 b


1 remittance, each electric utility shall file a tariff with 
2 the Commission no later than 30 days following the 
3 effective date of this amendatory Act of the 99th General 
4 Assembly, which the Commission shall approve, after notice 
5 and hearing, no later than 45 days after its filing. The 
6 Illinois Power Agency shall use such payments to increase 
7 the amount of renewable energy resources otherwise to be 
8 procured under subsection (c) of Section 1-75 of the 
9 Illinois Power Agency Act. 
10  (5) The Commission, in consultation with the Illinois 
11 Power Agency, shall establish a process or proceeding to 
12 consider the impact of a federal renewable portfolio 
13 standard, if enacted, on the operation of the alternative 
14 compliance mechanism, which shall include, but not be 
15 limited to, developing, to the extent permitted by the 
16 applicable federal statute, an appropriate methodology to 
17 apportion renewable energy credits retired as a result of 
18 alternative compliance payments made in accordance with 
19 this Section. The Commission shall commence any such 
20 process or proceeding within 35 days after enactment of a 
21 federal renewable portfolio standard.
22 (e) Each alternative retail electric supplier shall, by 
23September 1, 2010 and by September 1 of each year thereafter, 
24prepare and submit to the Commission a report, in a format to 
25be specified by the Commission, that provides information 
26certifying compliance by the alternative retail electric 
 
 
SB2552- 179 -LRB103 31416 LNS 59082 b


1supplier with this Section, including copies of all PJM-GATS 
2and M-RETS reports, and documentation relating to banking, 
3retiring renewable energy credits, and any other information 
4that the Commission determines necessary to ensure compliance 
5with this Section.
6 An alternative retail electric supplier may file 
7commercially or financially sensitive information or trade 
8secrets with the Commission as provided under the rules of the 
9Commission. To be filed confidentially, the information shall 
10be accompanied by an affidavit that sets forth both the 
11reasons for the confidentiality and a public synopsis of the 
12information.
13 (e-5)
Each alternative retail electric supplier shall make 
14payment to an applicable electric utility for capacity, 
15receive transfers of capacity credits, timely report capacity 
16credits procured on its behalf to the applicable regional 
17transmission organization, and submit the capacity credits to 
18the applicable regional transmission organization under that 
19regional transmission organization's rules and procedures, in 
20all respects as set out in subsection (b-10) of Section 
2116-111.5. The Commission shall have authority to adopt rules 
22for the certification by alternative retail electric suppliers 
23of their ongoing compliance with the requirements in this 
24subsection. 
25 (f) The Commission may initiate a contested case to review 
26allegations that the alternative retail electric supplier has 
 
 
SB2552- 180 -LRB103 31416 LNS 59082 b


1violated this Section, including an order issued or rule 
2promulgated under this Section. In any such proceeding, the 
3alternative retail electric supplier shall have the burden of 
4proof. If the Commission finds, after notice and hearing, that 
5an alternative retail electric supplier has violated this 
6Section, then the Commission shall issue an order requiring 
7the alternative retail electric supplier to:
8  (1) immediately comply with this Section; and
9  (2) if the violation involves a failure to procure the 
10 requisite quantity of renewable energy resources or pay 
11 the applicable alternative compliance payment by the 
12 annual deadline, the Commission shall require the 
13 alternative retail electric supplier to double the 
14 applicable alternative compliance payment that would 
15 otherwise be required to bring the alternative retail 
16 electric supplier into compliance with this Section.
17 If an alternative retail electric supplier fails to comply 
18with the renewable energy resource portfolio requirement or 
19capacity portfolio requirement in this Section more than once 
20in a 5-year period, then the Commission shall revoke the 
21alternative electric supplier's certificate of service 
22authority. The Commission shall not accept an application for 
23a certificate of service authority from an alternative retail 
24electric supplier that has lost certification under this 
25subsection (f), or any corporate affiliate thereof, for at 
26least one year after the date of revocation.
 
 
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1 (g) All of the provisions of this Section apply to 
2electric utilities operating outside their service area except 
3under item (2) of subsection (a) of this Section the quantity 
4of renewable energy resources shall be measured as a 
5percentage of the actual amount of electricity 
6(megawatt-hours) supplied in the State outside of the 
7utility's service territory during the 12-month period June 1 
8through May 31, commencing June 1, 2009, and the comparable 
912-month period in each year thereafter except as provided in 
10item (6) of subsection (a) of this Section.
11 If any such utility fails to procure the requisite 
12quantity of renewable energy resources by the annual deadline, 
13then the Commission shall require the utility to double the 
14alternative compliance payment that would otherwise be 
15required to bring the utility into compliance with this 
16Section.
17 If any such utility fails to comply with the renewable 
18energy resource portfolio requirement in this Section more 
19than once in a 5-year period, then the Commission shall order 
20the utility to cease all sales outside of the utility's 
21service territory for a period of at least one year.
22 (h) The provisions of this Section and the provisions of 
23subsection (d) of Section 16-115 of this Act relating to 
24procurement of renewable energy resources shall not apply to 
25an alternative retail electric supplier that operates a 
26combined heat and power system in this State or that has a 
 
 
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1corporate affiliate that operates such a combined heat and 
2power system in this State that supplies electricity primarily 
3to or for the benefit of: (i) facilities owned by the supplier, 
4its subsidiary, or other corporate affiliate; (ii) facilities 
5electrically integrated with the electrical system of 
6facilities owned by the supplier, its subsidiary, or other 
7corporate affiliate; or (iii) facilities that are adjacent to 
8the site on which the combined heat and power system is 
9located.

10 (i) The obligations of alternative retail electric 
11suppliers and electric utilities operating outside their 
12service territories to procure renewable energy resources, 
13make alternative compliance payments, and file annual reports, 
14and the obligations of the Commission to determine and post 
15alternative compliance payment rates, shall terminate after 
16May 31, 2019, provided that alternative retail electric 
17suppliers and electric utilities operating outside their 
18service territories shall be obligated to make all alternative 
19compliance payments that they were obligated to pay for 
20periods through and including May 31, 2019, but were not paid 
21as of that date. The Commission shall continue to enforce the 
22payment of unpaid alternative compliance payments in 
23accordance with subsections (f) and (g) of this Section. All 
24alternative compliance payments made after May 31, 2016 shall 
25be remitted to the applicable electric utility and used to 
26purchase renewable energy credits, in accordance with Section 
 
 
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11-75 of the Illinois Power Agency Act.
2 This subsection (i) is intended to accommodate the 
3transition to the procurement of renewable energy resources 
4for all retail customers in the amounts specified under 
5subsection (c) of Section 1-75 of the Illinois Power Agency 
6Act and Section 16-111.5 of this Act, including but not 
7limited to the transition to a single charge applicable to all 
8retail customers to recover the costs of these resources. Each 
9alternative retail electric supplier shall certify in its 
10annual reports filed pursuant to subsection (e) of this 
11Section after May 31, 2019, that its retail customers are not 
12paying the costs of alternative compliance payments or 
13renewable energy resources that the alternative retail 
14electric supplier is not required to remit or purchase under 
15this Section. The Commission shall have the authority to 
16initiate an emergency rulemaking to adopt rules regarding such 
17certification. 
18(Source: P.A. 99-906, eff. 6-1-17.)

 
 
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1
INDEX

2
Statutes amended in order of appearance