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 103RD GENERAL ASSEMBLY State of Illinois 2023 and 2024 SB2552 Introduced 3/23/2023, by Sen. David Koehler SYNOPSIS AS INTRODUCED: See Index 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 LRB103 31416 LNS 59082 b A BILL FOR
103RD GENERAL ASSEMBLY State of Illinois 2023 and 2024 SB2552 Introduced 3/23/2023, by Sen. David Koehler SYNOPSIS AS INTRODUCED:
See Index See Index
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.
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A BILL FOR
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1 AN ACT concerning regulation.
2 Be it enacted by the People of the State of Illinois,
3 represented in the General Assembly:
4 Section 5. The Illinois Power Agency Act is amended by
5 changing Section 1-20 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
103RD GENERAL ASSEMBLY State of Illinois 2023 and 2024 SB2552 Introduced 3/23/2023, by Sen. David Koehler SYNOPSIS AS INTRODUCED:
See Index See Index
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.
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A BILL FOR
See Index
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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
15 has all of the powers necessary or convenient to carry out the
16 purposes and provisions of this Act, including without
17 limitation, 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
19 products, beginning January 1, 2022, the Agency shall not
20 procure any products or services from persons or organizations
21 that are in violation of the Displaced Energy Workers Bill of
22 Rights, as provided under the Energy Community Reinvestment
23 Act at the time of the procurement event or fail to comply the
24 labor 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
2 changing Sections 3-105, 8-103B, 16-111.5, 16-115, and 16-115D
3 and 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
7 otherwise expressly provided in this Section, every
8 corporation, company, limited liability company, association,
9 joint stock company or association, firm, partnership or
10 individual, their lessees, trustees, or receivers appointed by
11 any court whatsoever now or hereafter that owns, controls,
12 operates or manages, within this State, directly or
13 indirectly, for public use, any plant, equipment or property
14 used or to be used for or in connection with, or owns or
15 controls or seeks Commission approval to own or control any
16 franchise, 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
15 electric vehicles does not and shall not be deemed to sell
16 electricity and is not and shall not be deemed a public utility
17 notwithstanding the basis on which the service is provided or
18 billed. If, however, the entity is otherwise deemed a public
19 utility under this Act, or is otherwise subject to regulation
20 under this Act, then that entity is not exempt from and remains
21 subject to the otherwise applicable provisions of this Act.
22 The installation, maintenance, and repair of an electric
23 vehicle charging station shall comply with the requirements of
24 subsection (a) of Section 16-128 and Section 16-128A of this
25 Act.
26 For purposes of this subsection, the term "electric
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1 vehicles" has the meaning ascribed to that term in Section 10
2 of 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
6 measures.
7 (a) It is the policy of the State that electric utilities
8 are required to use cost-effective energy efficiency and
9 demand-response measures to reduce delivery load. Requiring
10 investment in cost-effective energy efficiency and
11 demand-response measures will reduce direct and indirect costs
12 to consumers by decreasing environmental impacts and by
13 avoiding or delaying the need for new generation,
14 transmission, and distribution infrastructure. It serves the
15 public interest to allow electric utilities to recover costs
16 for reasonably and prudently incurred expenditures for energy
17 efficiency and demand-response measures. As used in this
18 Section, "cost-effective" means that the measures satisfy the
19 total resource cost test. The low-income measures described in
20 subsection (c) of this Section shall not be required to meet
21 the total resource cost test. For purposes of this Section,
22 the terms "energy-efficiency", "demand-response", "electric
23 utility", and "total resource cost test" have the meanings set
24 forth in the Illinois Power Agency Act. "Black, indigenous,
25 and people of color" and "BIPOC" means people who are members
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1 of the groups described in subparagraphs (a) through (e) of
2 paragraph (A) of subsection (1) of Section 2 of the Business
3 Enterprise for Minorities, Women, and Persons with
4 Disabilities Act.
5 (a-5) This Section applies to electric utilities serving
6 more than 500,000 retail customers in the State for those
7 multi-year plans commencing after December 31, 2017.
8 (b) For purposes of this Section, electric utilities
9 subject to this Section that serve more than 3,000,000 retail
10 customers in the State shall be deemed to have achieved a
11 cumulative persisting annual savings of 6.6% from energy
12 efficiency measures and programs implemented during the period
13 beginning January 1, 2012 and ending December 31, 2017, which
14 percent is based on the deemed average weather normalized
15 sales of electric power and energy during calendar years 2014,
16 2015, and 2016 of 88,000,000 MWhs. For the purposes of this
17 subsection (b) and subsection (b-5), the 88,000,000 MWhs of
18 deemed electric power and energy sales shall be reduced by the
19 number of MWhs equal to the sum of the annual consumption of
20 customers that have opted out of subsections (a) through (j)
21 of this Section under paragraph (1) of subsection (l) of this
22 Section, as averaged across the calendar years 2014, 2015, and
23 2016. After 2017, the deemed value of cumulative persisting
24 annual savings from energy efficiency measures and programs
25 implemented during the period beginning January 1, 2012 and
26 ending December 31, 2017, shall be reduced each year, as
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1 follows, and the applicable value shall be applied to and
2 count toward the utility's achievement of the cumulative
3 persisting 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
26 annual savings" means the total electric energy savings in a
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1 given year from measures installed in that year or in previous
2 years, but no earlier than January 1, 2012, that are still
3 operational and providing savings in that year because the
4 measures have not yet reached the end of their useful lives.
5 (b-5) Beginning in 2018, electric utilities subject to
6 this Section that serve more than 3,000,000 retail customers
7 in the State shall achieve the following cumulative persisting
8 annual savings goals, as modified by subsection (f) of this
9 Section and as compared to the deemed baseline of 88,000,000
10 MWhs of electric power and energy sales set forth in
11 subsection (b), as reduced by the number of MWhs equal to the
12 sum of the annual consumption of customers that have opted out
13 of subsections (a) through (j) of this Section under paragraph
14 (1) of subsection (l) of this Section as averaged across the
15 calendar years 2014, 2015, and 2016, through the
16 implementation of energy efficiency measures during the
17 applicable year and in prior years, but no earlier than
18 January 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
20 Commission shall establish additional cumulative persisting
21 annual savings goals for the years 2031 through 2035. No later
22 than December 31, 2024, the Illinois Commerce Commission shall
23 establish additional cumulative persisting annual savings
24 goals for the years 2036 through 2040. The Commission shall
25 also establish additional cumulative persisting annual savings
26 goals every 5 years thereafter to ensure that utilities always
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1 have goals that extend at least 11 years into the future. The
2 cumulative persisting annual savings goals beyond the year
3 2030 shall increase by 0.9 percentage points per year, absent
4 a Commission decision to initiate a proceeding to consider
5 establishing goals that increase by more or less than that
6 amount. Such a proceeding must be conducted in accordance with
7 the procedures described in subsection (f) of this Section. If
8 such a proceeding is initiated, the cumulative persisting
9 annual savings goals established by the Commission through
10 that proceeding shall reflect the Commission's best estimate
11 of the maximum amount of additional savings that are forecast
12 to be cost-effectively achievable unless such best estimates
13 would result in goals that represent less than 0.5 percentage
14 point annual increases in total cumulative persisting annual
15 savings. The Commission may only establish goals that
16 represent less than 0.5 percentage point annual increases in
17 cumulative persisting annual savings if it can demonstrate,
18 based on clear and convincing evidence and through independent
19 analysis, that 0.5 percentage point increases are not
20 cost-effectively achievable. The Commission shall inform its
21 decision based on an energy efficiency potential study that
22 conforms to the requirements of this Section.
23 (b-10) For purposes of this Section, electric utilities
24 subject to this Section that serve less than 3,000,000 retail
25 customers but more than 500,000 retail customers in the State
26 shall be deemed to have achieved a cumulative persisting
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1 annual savings of 6.6% from energy efficiency measures and
2 programs implemented during the period beginning January 1,
3 2012 and ending December 31, 2017, which is based on the deemed
4 average weather normalized sales of electric power and energy
5 during calendar years 2014, 2015, and 2016 of 36,900,000 MWhs.
6 For the purposes of this subsection (b-10) and subsection
7 (b-15), the 36,900,000 MWhs of deemed electric power and
8 energy sales shall be reduced by the number of MWhs equal to
9 the sum of the annual consumption of customers that have opted
10 out of subsections (a) through (j) of this Section under
11 paragraph (1) of subsection (l) of this Section, as averaged
12 across the calendar years 2014, 2015, and 2016. After 2017,
13 the deemed value of cumulative persisting annual savings from
14 energy efficiency measures and programs implemented during the
15 period beginning January 1, 2012 and ending December 31, 2017,
16 shall be reduced each year, as follows, and the applicable
17 value shall be applied to and count toward the utility's
18 achievement of the cumulative persisting annual savings goals
19 set 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
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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
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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
16 this Section that serve less than 3,000,000 retail customers
17 but more than 500,000 retail customers in the State shall
18 achieve the following cumulative persisting annual savings
19 goals, as modified by subsection (b-20) and subsection (f) of
20 this Section and as compared to the deemed baseline as reduced
21 by the number of MWhs equal to the sum of the annual
22 consumption of customers that have opted out of subsections
23 (a) through (j) of this Section under paragraph (1) of
24 subsection (l) of this Section as averaged across the calendar
25 years 2014, 2015, and 2016, through the implementation of
26 energy efficiency measures during the applicable year and in
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1 prior 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
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1 for the year ending December 31, 2030.
2 No later than December 31, 2021, the Illinois Commerce
3 Commission shall establish additional cumulative persisting
4 annual savings goals for the years 2031 through 2035. No later
5 than December 31, 2024, the Illinois Commerce Commission shall
6 establish additional cumulative persisting annual savings
7 goals for the years 2036 through 2040. The Commission shall
8 also establish additional cumulative persisting annual savings
9 goals every 5 years thereafter to ensure that utilities always
10 have goals that extend at least 11 years into the future. The
11 cumulative persisting annual savings goals beyond the year
12 2030 shall increase by 0.9 0.6 percentage points per year,
13 absent a Commission decision to initiate a proceeding to
14 consider establishing goals that increase by more or less than
15 that amount. Such a proceeding must be conducted in accordance
16 with the procedures described in subsection (f) of this
17 Section. If such a proceeding is initiated, the cumulative
18 persisting annual savings goals established by the Commission
19 through that proceeding shall reflect the Commission's best
20 estimate of the maximum amount of additional savings that are
21 forecast to be cost-effectively achievable unless such best
22 estimates would result in goals that represent less than 0.5
23 0.4 percentage point annual increases in total cumulative
24 persisting annual savings. The Commission may only establish
25 goals that represent less than 0.5 0.4 percentage point annual
26 increases in cumulative persisting annual savings if it can
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1 demonstrate, based on clear and convincing evidence and
2 through independent analysis, that 0.5 0.4 percentage point
3 increases are not cost-effectively achievable. The Commission
4 shall inform its decision based on an energy efficiency
5 potential study that conforms to the requirements of this
6 Section.
7 (b-20) Each electric utility subject to this Section may
8 include cost-effective voltage optimization measures in its
9 plans submitted under subsections (f) and (g) of this Section,
10 and the costs incurred by a utility to implement the measures
11 under a Commission-approved plan shall be recovered under the
12 provisions of Article IX or Section 16-108.5 of this Act. For
13 purposes of this Section, the measure life of voltage
14 optimization measures shall be 15 years. The measure life
15 period is independent of the depreciation rate of the voltage
16 optimization assets deployed. Utilities may claim savings from
17 voltage optimization on circuits for more than 15 years if
18 they can demonstrate that they have made additional
19 investments necessary to enable voltage optimization savings
20 to continue beyond 15 years. Such demonstrations must be
21 subject to the review of independent evaluation.
22 Within 270 days after June 1, 2017 (the effective date of
23 Public Act 99-906), an electric utility that serves less than
24 3,000,000 retail customers but more than 500,000 retail
25 customers in the State shall file a plan with the Commission
26 that identifies the cost-effective voltage optimization
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1 investment the electric utility plans to undertake through
2 December 31, 2024. The Commission, after notice and hearing,
3 shall approve or approve with modification the plan within 120
4 days after the plan's filing and, in the order approving or
5 approving with modification the plan, the Commission shall
6 adjust the applicable cumulative persisting annual savings
7 goals set forth in subsection (b-15) to reflect any amount of
8 cost-effective energy savings approved by the Commission that
9 is greater than or less than the following cumulative
10 persisting annual savings values attributable to voltage
11 optimization 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
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1 the year ending December 31, 2025 and all subsequent
2 years.
3 (b-25) In the event an electric utility jointly offers an
4 energy efficiency measure or program with a gas utility under
5 plans approved under this Section and Section 8-104 of this
6 Act, the electric utility may continue offering the program,
7 including the gas energy efficiency measures, in the event the
8 gas utility discontinues funding the program. In that event,
9 the energy savings value associated with such other fuels
10 shall be converted to electric energy savings on an equivalent
11 Btu basis for the premises. However, the electric utility
12 shall prioritize programs for low-income residential customers
13 to the extent practicable. An electric utility may recover the
14 costs of offering the gas energy efficiency measures under
15 this subsection (b-25).
16 For those energy efficiency measures or programs that save
17 both electricity and other fuels but are not jointly offered
18 with a gas utility under plans approved under this Section and
19 Section 8-104 or not offered with an affiliated gas utility
20 under paragraph (6) of subsection (f) of Section 8-104 of this
21 Act, the electric utility may count savings of fuels other
22 than electricity toward the achievement of its annual savings
23 goal, and the energy savings value associated with such other
24 fuels shall be converted to electric energy savings on an
25 equivalent Btu basis at the premises.
26 In no event shall more than 10% of each year's applicable
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1 annual total savings requirement as defined in paragraph (7.5)
2 of subsection (g) of this Section be met through savings of
3 fuels other than electricity.
4 (b-27) Beginning in 2022, an electric utility may offer
5 and promote measures that electrify space heating, water
6 heating, cooling, drying, cooking, industrial processes, and
7 other building and industrial end uses that would otherwise be
8 served by combustion of fossil fuel at the premises, provided
9 that the electrification measures reduce total energy
10 consumption at the premises. The electric utility may count
11 the reduction in energy consumption at the premises toward
12 achievement of its annual savings goals. The reduction in
13 energy consumption at the premises shall be calculated as the
14 difference between: (A) the reduction in Btu consumption of
15 fossil fuels as a result of electrification, converted to
16 kilowatt-hour equivalents by dividing by 3,412 Btus Btu's per
17 kilowatt hour; and (B) the increase in kilowatt hours of
18 electricity consumption resulting from the displacement of
19 fossil fuel consumption as a result of electrification. An
20 electric utility may recover the costs of offering and
21 promoting electrification measures under this subsection
22 (b-27).
23 In no event shall electrification savings counted toward
24 each year's applicable annual total savings requirement, as
25 defined in paragraph (7.5) of subsection (g) of this Section,
26 be greater than:
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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.
5 In addition, a minimum of 25% of all electrification savings
6 counted toward a utility's applicable annual total savings
7 requirement must be from electrification of end uses in
8 low-income housing. The limitations on electrification savings
9 that may be counted toward a utility's annual savings goals
10 are separate from and in addition to the subsection (b-25)
11 limitations governing the counting of the other fuel savings
12 resulting from efficiency measures and programs.
13 As part of the annual informational filing to the
14 Commission that is required under paragraph (9) of subsection
15 (g) of this Section, each utility shall identify the specific
16 electrification measures offered under this subsection
17 subjection (b-27); the quantity of each electrification
18 measure that was installed by its customers; the average total
19 cost, average utility cost, average reduction in fossil fuel
20 consumption, and average increase in electricity consumption
21 associated with each electrification measure; the portion of
22 installations of each electrification measure that were in
23 low-income single-family housing, low-income multifamily
24 housing, non-low-income single-family housing, non-low-income
25 multifamily housing, commercial buildings, and industrial
26 facilities; and the quantity of savings associated with each
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1 measure category in each customer category that are being
2 counted toward the utility's applicable annual total savings
3 requirement. Prior to installing an electrification measure,
4 the utility shall provide a customer with an estimate of the
5 impact of the new measure on the customer's average monthly
6 electric bill and total annual energy expenses.
7 (c) Electric utilities shall be responsible for overseeing
8 the design, development, and filing of energy efficiency plans
9 with the Commission and may, as part of that implementation,
10 outsource various aspects of program development and
11 implementation. A minimum of 10%, for electric utilities that
12 serve more than 3,000,000 retail customers in the State, and a
13 minimum of 7%, for electric utilities that serve less than
14 3,000,000 retail customers but more than 500,000 retail
15 customers in the State, of the utility's entire portfolio
16 funding level for a given year shall be used to procure
17 cost-effective energy efficiency measures from units of local
18 government, municipal corporations, school districts, public
19 housing, and community college districts, provided that a
20 minimum percentage of available funds shall be used to procure
21 energy efficiency from public housing, which percentage shall
22 be equal to public housing's share of public building energy
23 consumption.
24 The utilities shall also implement energy efficiency
25 measures targeted at low-income households, which, for
26 purposes of this Section, shall be defined as households at or
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1 below 80% of area median income, and expenditures to implement
2 the measures shall be no less than $40,000,000 per year for
3 electric utilities that serve more than 3,000,000 retail
4 customers in the State and no less than $13,000,000 per year
5 for electric utilities that serve less than 3,000,000 retail
6 customers but more than 500,000 retail customers in the State.
7 The ratio of spending on efficiency programs targeted at
8 low-income multifamily buildings to spending on efficiency
9 programs targeted at low-income single-family buildings shall
10 be designed to achieve levels of savings from each building
11 type that are approximately proportional to the magnitude of
12 cost-effective lifetime savings potential in each building
13 type. Investment in low-income whole-building weatherization
14 programs shall constitute a minimum of 80% of a utility's
15 total budget specifically dedicated to serving low-income
16 customers.
17 The utilities shall work to bundle low-income energy
18 efficiency offerings with other programs that serve low-income
19 households to maximize the benefits going to these households.
20 The utilities shall market and implement low-income energy
21 efficiency programs in coordination with low-income assistance
22 programs, the Illinois Solar for All Program, and
23 weatherization whenever practicable. The program implementer
24 shall walk the customer through the enrollment process for any
25 programs for which the customer is eligible. The utilities
26 shall also pilot targeting customers with high arrearages,
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1 high energy intensity (ratio of energy usage divided by home
2 or unit square footage), or energy assistance programs with
3 energy efficiency offerings, and then track reduction in
4 arrearages as a result of the targeting. This targeting and
5 bundling of low-income energy programs shall be offered to
6 both low-income single-family and multifamily customers
7 (owners and residents).
8 The utilities shall invest in health and safety measures
9 appropriate and necessary for comprehensively weatherizing a
10 home or multifamily building, and shall implement a health and
11 safety fund of at least 15% of the total income-qualified
12 weatherization budget that shall be used for the purpose of
13 making grants for technical assistance, construction,
14 reconstruction, improvement, or repair of buildings to
15 facilitate their participation in the energy efficiency
16 programs targeted at low-income single-family and multifamily
17 households. These funds may also be used for the purpose of
18 making grants for technical assistance, construction,
19 reconstruction, improvement, or repair of the following
20 buildings to facilitate their participation in the energy
21 efficiency programs created by this Section: (1) buildings
22 that are owned or operated by registered 501(c)(3) public
23 charities; and (2) day care centers, day care homes, or group
24 day care homes, as defined under 89 Ill. Adm. Code Part 406,
25 407, or 408, respectively.
26 Each electric utility shall assess opportunities to
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1 implement cost-effective energy efficiency measures and
2 programs through a public housing authority or authorities
3 located in its service territory. If such opportunities are
4 identified, the utility shall propose such measures and
5 programs to address the opportunities. Expenditures to address
6 such opportunities shall be credited toward the minimum
7 procurement and expenditure requirements set forth in this
8 subsection (c).
9 Implementation of energy efficiency measures and programs
10 targeted at low-income households should be contracted, when
11 it is practicable, to independent third parties that have
12 demonstrated capabilities to serve such households, with a
13 preference for not-for-profit entities and government agencies
14 that have existing relationships with or experience serving
15 low-income communities in the State.
16 Each electric utility shall develop and implement
17 reporting procedures that address and assist in determining
18 the amount of energy savings that can be applied to the
19 low-income procurement and expenditure requirements set forth
20 in this subsection (c). Each electric utility shall also track
21 the types and quantities or volumes of insulation and air
22 sealing materials, and their associated energy saving
23 benefits, installed in energy efficiency programs targeted at
24 low-income single-family and multifamily households.
25 The electric utilities shall participate in a low-income
26 energy efficiency accountability committee ("the committee"),
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1 which will directly inform the design, implementation, and
2 evaluation of the low-income and public-housing energy
3 efficiency programs. The committee shall be comprised of the
4 electric utilities subject to the requirements of this
5 Section, the gas utilities subject to the requirements of
6 Section 8-104 of this Act, the utilities' low-income energy
7 efficiency implementation contractors, nonprofit
8 organizations, community action agencies, advocacy groups,
9 State and local governmental agencies, public-housing
10 organizations, and representatives of community-based
11 organizations, especially those living in or working with
12 environmental justice communities and BIPOC communities. The
13 committee shall be composed of 2 geographically differentiated
14 subcommittees: one for stakeholders in northern Illinois and
15 one for stakeholders in central and southern Illinois. The
16 subcommittees shall meet together at least twice per year.
17 There shall be one statewide leadership committee led by
18 and composed of community-based organizations that are
19 representative of BIPOC and environmental justice communities
20 and that includes equitable representation from BIPOC
21 communities. The leadership committee shall be composed of an
22 equal number of representatives from the 2 subcommittees. The
23 subcommittees shall address specific programs and issues, with
24 the leadership committee convening targeted workgroups as
25 needed. The leadership committee may elect to work with an
26 independent facilitator to solicit and organize feedback,
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1 recommendations and meeting participation from a wide variety
2 of community-based stakeholders. If a facilitator is used,
3 they shall be fair and responsive to the needs of all
4 stakeholders involved in the committee.
5 All committee meetings must be accessible, with rotating
6 locations if meetings are held in-person, virtual
7 participation options, and materials and agendas circulated in
8 advance.
9 There shall also be opportunities for direct input by
10 committee members outside of committee meetings, such as via
11 individual meetings, surveys, emails and calls, to ensure
12 robust participation by stakeholders with limited capacity and
13 ability to attend committee meetings. Committee meetings shall
14 emphasize opportunities to bundle and coordinate delivery of
15 low-income energy efficiency with other programs that serve
16 low-income communities, such as the Illinois Solar for All
17 Program and bill payment assistance programs. Meetings shall
18 include educational opportunities for stakeholders to learn
19 more about these additional offerings, and the committee shall
20 assist in figuring out the best methods for coordinated
21 delivery and implementation of offerings when serving
22 low-income communities. The committee shall directly and
23 equitably influence and inform utility low-income and
24 public-housing energy efficiency programs and priorities.
25 Participating utilities shall implement recommendations from
26 the committee whenever possible.
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1 Participating utilities shall track and report how input
2 from the committee has led to new approaches and changes in
3 their energy efficiency portfolios. This reporting shall occur
4 at committee meetings and in quarterly energy efficiency
5 reports to the Stakeholder Advisory Group and Illinois
6 Commerce Commission, and other relevant reporting mechanisms.
7 Participating utilities shall also report on relevant equity
8 data and metrics requested by the committee, such as energy
9 burden data, geographic, racial, and other relevant
10 demographic data on where programs are being delivered and
11 what populations programs are serving.
12 The Illinois Commerce Commission shall oversee and have
13 relevant staff participate in the committee. The committee
14 shall have a budget of 0.25% of each utility's entire
15 efficiency portfolio funding for a given year. The budget
16 shall be overseen by the Commission. The budget shall be used
17 to provide grants for community-based organizations serving on
18 the leadership committee, stipends for community-based
19 organizations participating in the committee, grants for
20 community-based organizations to do energy efficiency outreach
21 and education, and relevant meeting needs as determined by the
22 leadership committee. The education and outreach shall
23 include, but is not limited to, basic energy efficiency
24 education, information about low-income energy efficiency
25 programs, and information on the committee's purpose,
26 structure, and activities.
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1 (d) Notwithstanding any other provision of law to the
2 contrary, a utility providing approved energy efficiency
3 measures and, if applicable, demand-response measures in the
4 State shall be permitted to recover all reasonable and
5 prudently incurred costs of those measures from all retail
6 customers, except as provided in subsection (l) of this
7 Section, 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
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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
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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.
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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;
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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
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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
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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
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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
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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
23 Public Act 99-906), a utility subject to the requirements of
24 this Section may elect to defer, as a regulatory asset, up to
25 the full amount of its expenditures incurred under this
26 Section for each annual period, including, but not limited to,
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1 any expenditures incurred above the funding level set by
2 subsection (f) of this Section for a given year. The total
3 expenditures deferred as a regulatory asset in a given year
4 shall be amortized and recovered over a period that is equal to
5 the weighted average of the energy efficiency measure lives
6 implemented for that year that are reflected in the regulatory
7 asset. The unamortized balance shall be recognized as of
8 December 31 for a given year. The utility shall also earn a
9 return on the total of the unamortized balances of all of the
10 energy efficiency regulatory assets, less any deferred taxes
11 related to those unamortized balances, at an annual rate equal
12 to the utility's weighted average cost of capital that
13 includes, based on a year-end capital structure, the utility's
14 actual cost of debt for the applicable calendar year and a cost
15 of equity, which shall be calculated as the sum of the (i) the
16 average for the applicable calendar year of the monthly
17 average yields of 30-year U.S. Treasury bonds published by the
18 Board of Governors of the Federal Reserve System in its weekly
19 H.15 Statistical Release or successor publication; and (ii)
20 580 basis points, including a revenue conversion factor
21 calculated to recover or refund all additional income taxes
22 that may be payable or receivable as a result of that return.
23 Capital investment costs shall be depreciated and recovered
24 over their useful lives consistent with generally accepted
25 accounting principles. The weighted average cost of capital
26 shall be applied to the capital investment cost balance, less
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1 any accumulated depreciation and accumulated deferred income
2 taxes, as of December 31 for a given year.
3 When an electric utility creates a regulatory asset under
4 the provisions of this Section, the costs are recovered over a
5 period during which customers also receive a benefit which is
6 in the public interest. Accordingly, it is the intent of the
7 General Assembly that an electric utility that elects to
8 create a regulatory asset under the provisions of this Section
9 shall recover all of the associated costs as set forth in this
10 Section. After the Commission has approved the prudence and
11 reasonableness of the costs that comprise the regulatory
12 asset, the electric utility shall be permitted to recover all
13 such costs, and the value and recoverability through rates of
14 the associated regulatory asset shall not be limited, altered,
15 impaired, or reduced.
16 (f) Beginning in 2017, each electric utility shall file an
17 energy efficiency plan with the Commission to meet the energy
18 efficiency standards for the next applicable multi-year period
19 beginning January 1 of the year following the filing,
20 according to the schedule set forth in paragraphs (1) through
21 (3) of this subsection (f). If a utility does not file such a
22 plan on or before the applicable filing deadline for the plan,
23 it shall face a penalty of $100,000 per day until the plan is
24 filed.
25 (1) No later than 30 days after June 1, 2017 (the
26 effective date of Public Act 99-906), each electric
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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
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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
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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
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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
10 proposals to meet the energy efficiency standards identified
11 in subsection (b-5) or (b-15), as applicable and as such
12 standards may have been modified under this subsection (f),
13 taking into account the unique circumstances of the utility's
14 service territory. For those plans commencing on January 1,
15 2018, the Commission shall seek public comment on the
16 utility's plan and shall issue an order approving or
17 disapproving each plan no later than 105 days after June 1,
18 2017 (the effective date of Public Act 99-906). For those
19 plans commencing after December 31, 2021, the Commission shall
20 seek public comment on the utility's plan and shall issue an
21 order approving or disapproving each plan within 6 months
22 after its submission. If the Commission disapproves a plan,
23 the Commission shall, within 30 days, describe in detail the
24 reasons for the disapproval and describe a path by which the
25 utility may file a revised draft of the plan to address the
26 Commission's concerns satisfactorily. If the utility does not
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1 refile with the Commission within 60 days, the utility shall
2 be subject to penalties at a rate of $100,000 per day until the
3 plan is filed. This process shall continue, and penalties
4 shall accrue, until the utility has successfully filed a
5 portfolio of energy efficiency and demand-response measures.
6 Penalties shall be deposited into the Energy Efficiency Trust
7 Fund.
8 (g) In submitting proposed plans and funding levels under
9 subsection (f) of this Section to meet the savings goals
10 identified in subsection (b-5) or (b-15) of this Section, as
11 applicable, 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
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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
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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.
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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
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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
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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
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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 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
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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
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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
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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
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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
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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
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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
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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
26 demand-response program revenue may be allocated for research,
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1 development, or pilot deployment of new equipment or measures.
2 Electric utilities shall work with interested stakeholders to
3 formulate a plan for how these funds should be spent,
4 incorporate statewide approaches for these allocations, and
5 file a 4-year plan that demonstrates that collaboration. If a
6 utility files a request for modified annual energy savings
7 goals with the Commission, then a utility shall forgo spending
8 portfolio dollars on research and development proposals.
9 (i) When practicable, electric utilities shall incorporate
10 advanced metering infrastructure data into the planning,
11 implementation, and evaluation of energy efficiency measures
12 and programs, subject to the data privacy and confidentiality
13 protections of applicable law.
14 (j) The independent evaluator shall follow the guidelines
15 and use the savings set forth in Commission-approved energy
16 efficiency policy manuals and technical reference manuals, as
17 each may be updated from time to time. Until such time as
18 measure life values for energy efficiency measures implemented
19 for low-income households under subsection (c) of this Section
20 are incorporated into such Commission-approved manuals, the
21 low-income measures shall have the same measure life values
22 that are established for same measures implemented in
23 households that are not low-income households.
24 (k) Notwithstanding any provision of law to the contrary,
25 an electric utility subject to the requirements of this
26 Section may file a tariff cancelling an automatic adjustment
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1 clause tariff in effect under this Section or Section 8-103,
2 which shall take effect no later than one business day after
3 the date such tariff is filed. Thereafter, the utility shall
4 be authorized to defer and recover its expenditures incurred
5 under this Section through a new tariff authorized under
6 subsection (d) of this Section or in the utility's next rate
7 case under Article IX or Section 16-108.5 of this Act, with
8 interest at an annual rate equal to the utility's weighted
9 average cost of capital as approved by the Commission in such
10 case. If the utility elects to file a new tariff under
11 subsection (d) of this Section, the utility may file the
12 tariff within 10 days after June 1, 2017 (the effective date of
13 Public Act 99-906), and the cost inputs to such tariff shall be
14 based on the projected costs to be incurred by the utility
15 during the calendar year in which the new tariff is filed and
16 that were not recovered under the tariff that was cancelled as
17 provided for in this subsection. Such costs shall include
18 those incurred or to be incurred by the utility under its
19 multi-year plan approved under subsections (f) and (g) of this
20 Section, including, but not limited to, projected capital
21 investment costs and projected regulatory asset balances with
22 correspondingly updated depreciation and amortization reserves
23 and expense. The Commission shall, after notice and hearing,
24 approve, or approve with modification, such tariff and cost
25 inputs no later than 75 days after the utility filed the
26 tariff, provided that such approval, or approval with
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1 modification, shall be consistent with the provisions of this
2 Section to the extent they do not conflict with this
3 subsection (k). The tariff approved by the Commission shall
4 take effect no later than 5 days after the Commission enters
5 its order approving the tariff.
6 No later than 60 days after the effective date of the
7 tariff cancelling the utility's automatic adjustment clause
8 tariff, the utility shall file a reconciliation that
9 reconciles the moneys collected under its automatic adjustment
10 clause tariff with the costs incurred during the period
11 beginning June 1, 2016 and ending on the date that the electric
12 utility's automatic adjustment clause tariff was cancelled. In
13 the event the reconciliation reflects an under-collection, the
14 utility shall recover the costs as specified in this
15 subsection (k). If the reconciliation reflects an
16 over-collection, the utility shall apply the amount of such
17 over-collection as a one-time credit to retail customers'
18 bills.
19 (l) (Blank). For the calendar years covered by a
20 multi-year plan commencing after December 31, 2017,
21 subsections (a) through (j) of this Section do not apply to
22 eligible large private energy customers that have chosen to
23 opt 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,
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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
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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,
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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
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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
15 part of a proceeding to approve a multi-year plan under
16 subsections (f) and (g) of this Section if the multi-year plan
17 has been designed to maximize savings, but does not meet the
18 cost cap limitations of this Section, the Commission shall
19 reduce the amount of energy efficiency measures implemented
20 for any single year, and whose costs are recovered under
21 subsection (d) of this Section, by an amount necessary to
22 limit the estimated average net increase due to the cost of the
23 measures to no more than
24 (1) 3.5% for each of the 4 years beginning January 1,
25 2018,
26 (2) (blank),
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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,
8 of the average amount paid per kilowatthour by residential
9 eligible retail customers during calendar year 2015. An
10 electric utility may plan to spend up to 10% more in any year
11 during an applicable multi-year plan period to
12 cost-effectively achieve additional savings so long as the
13 average over the applicable multi-year plan period does not
14 exceed the percentages defined in items (1) through (5). To
15 determine the total amount that may be spent by an electric
16 utility in any single year, the applicable percentage of the
17 average amount paid per kilowatthour shall be multiplied by
18 the total amount of energy delivered by such electric utility
19 in the calendar year 2015, adjusted to reflect the proportion
20 of the utility's load attributable to customers that have
21 opted out of subsections (a) through (j) of this Section under
22 subsection (l) of this Section. For purposes of this
23 subsection (m), the amount paid per kilowatthour includes,
24 without limitation, estimated amounts paid for supply,
25 transmission, distribution, surcharges, and add-on taxes. For
26 purposes of this Section, "eligible retail customers" shall
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1 have the meaning set forth in Section 16-111.5 of this Act.
2 Once the Commission has approved a plan under subsections (f)
3 and (g) of this Section, no subsequent rate impact
4 determinations shall be made.
5 (n) A utility shall take advantage of the efficiencies
6 available through existing Illinois Home Weatherization
7 Assistance Program infrastructure and services, such as
8 enrollment, marketing, quality assurance and implementation,
9 which can reduce the need for similar services at a lower cost
10 than utility-only programs, subject to capacity constraints at
11 community action agencies, for both single-family and
12 multifamily weatherization services, to the extent Illinois
13 Home Weatherization Assistance Program community action
14 agencies provide multifamily services. A utility's plan shall
15 demonstrate that in formulating annual weatherization budgets,
16 it has sought input and coordination with community action
17 agencies regarding agencies' capacity to expand and maximize
18 Illinois Home Weatherization Assistance Program delivery using
19 the ratepayer dollars collected under this Section.
20 (Source: P.A. 101-81, eff. 7-12-19; 102-662, eff. 9-15-21;
21 revised 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
25 pricing plans can lower energy costs for consumers and reduce
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1 grid costs as well as help the State achieve its energy policy
2 goals by improving load shape, encouraging energy
3 conservation, and shifting usage away from periods where
4 fossil fuels are used to meet peak demand. Further, by
5 providing consumers information relating the costs of service
6 to the time of energy usage, time-of-use rates can help
7 consumers reduce their energy bills by using electricity when
8 it is less costly. Time-of-use rates can help allocate
9 electricity system costs more accurately and thus equitably to
10 those who cause costs. Such rates can reduce the need for
11 ramping resources and increase the grid's ability to
12 cost-effectively integrate greater quantities of variable
13 renewable energy and distributed energy resources.
14 (b) An electric utility that has a tariff approved under
15 subsection (d) of Section 16-108.18 within one year of this
16 amendatory Act of the 103rd General Assembly shall also offer
17 at least one market-based, time-of-use rate for eligible
18 retail customers that choose to take power and energy supply
19 service from the utility. If the utility has a pending request
20 for approval of a Multi-Year Integrated Grid Plan, the utility
21 shall update its filing in that docket to reflect the likely
22 impacts of the time-of-use rate offering. The utility shall
23 file its time-of-use rate tariff no later than 120 days after
24 the effective date of this amendatory Act of the 103rd General
25 Assembly, and each utility subject to this requirement shall
26 implement the requirements of this subsection by filing a
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1 tariff with the Commission. The tariff or tariffs shall be
2 subject 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
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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"
16 includes, but is not limited to, customers participating in
17 net electricity metering under the terms of Section 16-107.5.
18 (c) The Commission shall, after notice and hearing,
19 approve the tariff or tariffs with modifications the
20 Commission finds necessary to improve the program design,
21 customer participation in the program, or coordination with
22 existing utility pricing programs, energy efficiency programs,
23 demand response programs, and any other programs supporting
24 State energy policy goals and the integration of distributed
25 energy resources. The Commission shall also consider how the
26 proposed time-of-use rate design reflects the system costs and
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1 usage patterns of the utility. A proceeding under this
2 subsection may not exceed 120 days in length.
3 (d) If the Commission issues an order pursuant to this
4 subsection, the affected electric utility shall contract with
5 an entity not affiliated with the electric utility to serve as
6 a program administrator to develop and implement a program to
7 provide consumer outreach, enrollment, and education
8 concerning time-of-use pricing and to establish and administer
9 an information system and technical and other customer
10 assistance that is necessary to enable customers to manage
11 electricity use. The program administrator: (i) shall be
12 selected and compensated by the electric utility, subject to
13 Commission approval; (ii) shall have demonstrated technical
14 and managerial competence in the development and
15 administration of demand management programs; and (iii) may
16 develop and implement risk management, energy efficiency, and
17 other services related to energy use management for which the
18 program administrator shall be compensated by participants in
19 the program receiving such services. The electric utility
20 shall provide the program administrator with all information
21 and assistance necessary to perform the program
22 administrator's duties, including, but not limited to,
23 customer, account, and energy use data. The electric utility
24 shall permit the program administrator to include inserts in
25 residential customer bills 2 times per year to assist with
26 customer outreach and enrollment. The program administrator
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1 shall submit an annual report to the electric utility no later
2 than April 1 of each year describing the operation and results
3 of the program, including information concerning the number
4 and types of customers using the program, changes in
5 customers' energy use patterns, an assessment of the value of
6 the program to both participants and nonparticipants, and
7 recommendations concerning modification of the program and the
8 tariff or tariffs filed under this Section. This report shall
9 be filed by the electric utility with the Commission within 30
10 days after receipt and shall be available to the public on the
11 Commission's website.
12 (e) Once the tariff or tariffs has been in effect for 12
13 months, the Commission may, upon complaint, petition, or its
14 own initiative, open a proceeding to investigate whether
15 changes or modifications to the tariff or tariffs, program
16 administration and any other program design element is
17 necessary to achieve the goals described in subsection (a) and
18 to shifting usage away from periods where fossil fuels are
19 used to meet peak demand and realign usage to periods when
20 renewable generation is available. Such a proceeding may not
21 last more than 180 days from the date upon which the
22 investigation is opened by Commission order. Thereafter, the
23 Commission may, upon complaint, petition, or its own
24 initiative, open a proceeding to investigate changes or
25 modifications to the tariff or tariffs at any time the
26 Commission deems reasonable in order to achieve these
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1 objectives.
2 (f) An electric utility shall be entitled to recover
3 reasonable costs incurred in complying with this Section, if
4 the recovery of the costs is fairly apportioned among its
5 residential customers.
6 (g) The electric utility's tariff or tariffs filed
7 pursuant to this Section shall be subject to the provisions of
8 Article IX of this Act insofar as they do not conflict with
9 this Section.
10 (h) This Section does not apply to any electric utility
11 providing 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
15 at least 100,000 customers in Illinois shall procure power and
16 energy for its eligible retail customers in accordance with
17 the applicable provisions set forth in Section 1-75 of the
18 Illinois Power Agency Act and this Section. Beginning with the
19 delivery year commencing on June 1, 2017, such electric
20 utility shall also procure zero emission credits from zero
21 emission facilities in accordance with the applicable
22 provisions set forth in Section 1-75 of the Illinois Power
23 Agency Act, and, for years beginning on or after June 1, 2017,
24 the utility shall procure renewable energy resources in
25 accordance with the applicable provisions set forth in Section
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1 1-75 of the Illinois Power Agency Act and this Section.
2 Beginning with the delivery year commencing on June 1, 2022,
3 an electric utility serving over 3,000,000 customers shall
4 also procure carbon mitigation credits from carbon-free energy
5 resources in accordance with the applicable provisions set
6 forth in Section 1-75 of the Illinois Power Agency Act and this
7 Section. A small multi-jurisdictional electric utility that on
8 December 31, 2005 served less than 100,000 customers in
9 Illinois may elect to procure power and energy for all or a
10 portion of its eligible Illinois retail customers in
11 accordance with the applicable provisions set forth in this
12 Section and Section 1-75 of the Illinois Power Agency Act.
13 This Section shall not apply to a small multi-jurisdictional
14 utility until such time as a small multi-jurisdictional
15 utility requests the Illinois Power Agency to prepare a
16 procurement plan for its eligible retail customers. "Eligible
17 retail customers" for the purposes of this Section means those
18 retail customers that purchase power and energy from the
19 electric utility under fixed-price bundled service tariffs,
20 other than those retail customers whose service is declared or
21 deemed competitive under Section 16-113 and those other
22 customer groups specified in this Section, including
23 self-generating customers, customers electing hourly pricing,
24 or those customers who are otherwise ineligible for
25 fixed-price bundled tariff service. For those customers that
26 are excluded from the procurement plan's electric supply
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1 service requirements, and the utility shall procure any supply
2 requirements, including capacity, ancillary services, and
3 hourly priced energy, in the applicable markets as needed to
4 serve those customers, provided that the utility may include
5 in its procurement plan load requirements for the load that is
6 associated with those retail customers whose service has been
7 declared or deemed competitive pursuant to Section 16-113 of
8 this Act to the extent that those customers are purchasing
9 power and energy during one of the transition periods
10 identified in subsection (b) of Section 16-113 of this Act.
11 (b) A procurement plan shall be prepared for each electric
12 utility consistent with the applicable requirements of the
13 Illinois Power Agency Act and this Section. For purposes of
14 this Section, Illinois electric utilities that are affiliated
15 by virtue of a common parent company are considered to be a
16 single electric utility. Small multi-jurisdictional utilities
17 may request a procurement plan for a portion of or all of its
18 Illinois load. Each procurement plan shall analyze the
19 projected balance of supply and demand for those retail
20 customers to be included in the plan's electric supply service
21 requirements over a 5-year period, with the first planning
22 year beginning on June 1 of the year following the year in
23 which the plan is filed. The plan shall specifically identify
24 the wholesale products to be procured following plan approval,
25 and shall follow all the requirements set forth in the Public
26 Utilities Act and all applicable State and federal laws,
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1 statutes, rules, or regulations, as well as Commission orders.
2 Nothing in this Section precludes consideration of contracts
3 longer than 5 years and related forecast data. Unless
4 specified otherwise in this Section, in the procurement plan
5 or in the implementing tariff, any procurement occurring in
6 accordance with this plan shall be competitively bid through a
7 request for proposals process. Approval and implementation of
8 the procurement plan shall be subject to review and approval
9 by the Commission according to the provisions set forth in
10 this Section. A procurement plan shall include each of the
11 following 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
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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.
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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
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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
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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.
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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,
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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
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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.
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1 (b-5) An electric utility that as of January 1, 2019
2 served more than 300,000 retail customers in this State shall
3 purchase renewable energy credits from new renewable energy
4 facilities constructed at or adjacent to the sites of
5 coal-fueled electric generating facilities in this State in
6 accordance with subsection (c-5) of Section 1-75 of the
7 Illinois Power Agency Act. Except as expressly provided in
8 this Section, the plans and procedures for such procurements
9 shall not be included in the procurement plans provided for in
10 this Section, but rather shall be conducted and implemented
11 solely in accordance with subsection (c-5) of Section 1-75 of
12 the 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.
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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.
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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.
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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
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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
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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
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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).
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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
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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
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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
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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
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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
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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
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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
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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
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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
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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
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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
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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
17 to procurements conducted pursuant to subsection (c-5) of
18 Section 1-75 of the Illinois Power Agency Act. However, the
19 Agency may retain a procurement administrator to assist the
20 Agency in planning and carrying out the procurement events and
21 implementing the other requirements specified in such
22 subsection (c-5) of Section 1-75 of the Illinois Power Agency
23 Act, with the costs incurred by the Agency for the procurement
24 administrator to be recovered through fees charged to
25 applicants for selection to sell and deliver renewable energy
26 credits to electric utilities pursuant to subsection (c-5) of
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1 Section 1-75 of the Illinois Power Agency Act. The procurement
2 process set forth in Section 1-75 of the Illinois Power Agency
3 Act and subsection (e) of this Section shall be administered
4 by a procurement administrator and monitored by a procurement
5 monitor.
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
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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
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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
21 process 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
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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
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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
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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
16 following 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
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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
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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
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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
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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,
19 the procurement administrator shall submit a confidential
20 report to the Commission. The report shall contain the results
21 of the bidding for each of the products along with the
22 procurement administrator's recommendation for the acceptance
23 and rejection of bids based on the price benchmark criteria
24 and other factors observed in the process. The procurement
25 monitor also shall submit a confidential report to the
26 Commission within 2 business days after opening the sealed
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1 bids. The report shall contain the procurement monitor's
2 assessment of bidder behavior in the process as well as an
3 assessment of the procurement administrator's compliance with
4 the procurement process and rules. The Commission shall review
5 the confidential reports submitted by the procurement
6 administrator and procurement monitor, and shall accept or
7 reject the recommendations of the procurement administrator
8 within 2 business days after receipt of the reports.
9 (g) Within 3 business days after the Commission decision
10 approving the results of a procurement event, the utility
11 shall enter into binding contractual arrangements with the
12 winning suppliers using the standard form contracts; except
13 that the utility shall not be required either directly or
14 indirectly to execute the contracts if a tariff that is
15 consistent with subsection (l) of this Section has not been
16 approved and placed into effect for that utility.
17 (h) For the procurement of standard wholesale products,
18 the names of the successful bidders and the load weighted
19 average of the winning bid prices for each contract type and
20 for each contract term shall be made available to the public at
21 the time of Commission approval of a procurement event. For
22 procurements conducted to meet the requirements of subsection
23 (b) of Section 1-56 or subsection (c) of Section 1-75 of the
24 Illinois Power Agency Act governed by the provisions of this
25 Section, the address and nameplate capacity of the new
26 renewable energy generating facility proposed by a winning
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1 bidder shall also be made available to the public at the time
2 of Commission approval of a procurement event, along with the
3 business address and contact information for any winning
4 bidder. An estimate or approximation of the nameplate capacity
5 of the new renewable energy generating facility may be
6 disclosed if necessary to protect the confidentiality of
7 individual bid prices.
8 The Commission, the procurement monitor, the procurement
9 administrator, the Illinois Power Agency, and all participants
10 in the procurement process shall maintain the confidentiality
11 of all other supplier and bidding information in a manner
12 consistent with all applicable laws, rules, regulations, and
13 tariffs. Confidential information, including the confidential
14 reports submitted by the procurement administrator and
15 procurement monitor pursuant to subsection (f) of this
16 Section, shall not be made publicly available and shall not be
17 discoverable by any party in any proceeding, absent a
18 compelling demonstration of need, nor shall those reports be
19 admissible in any proceeding other than one for law
20 enforcement purposes.
21 (i) Within 2 business days after a Commission decision
22 approving the results of a procurement event or such other
23 date as may be required by the Commission from time to time,
24 the utility shall file for informational purposes with the
25 Commission its actual or estimated retail supply charges, as
26 applicable, by customer supply group reflecting the costs
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1 associated with the procurement and computed in accordance
2 with the tariffs filed pursuant to subsection (l) of this
3 Section and approved by the Commission.
4 (j) Within 60 days following August 28, 2007 (the
5 effective date of Public Act 95-481), each electric utility
6 that on December 31, 2005 provided electric service to at
7 least 100,000 customers in Illinois shall prepare and file
8 with the Commission an initial procurement plan, which shall
9 conform in all material respects to the requirements of the
10 procurement plan set forth in subsection (b); provided,
11 however, that the Illinois Power Agency Act shall not apply to
12 the initial procurement plan prepared pursuant to this
13 subsection. The initial procurement plan shall identify the
14 portfolio of power and energy products to be procured and
15 delivered for the period June 2008 through May 2009, and shall
16 identify the proposed procurement administrator, who shall
17 have the same experience and expertise as is required of a
18 procurement administrator hired pursuant to Section 1-75 of
19 the Illinois Power Agency Act. Copies of the procurement plan
20 shall be posted and made publicly available on the
21 Commission's website. The initial procurement plan may include
22 contracts 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
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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
24 under this Section and subsection (c-5) of Section 1-75 of the
25 Illinois Power Agency Act, including, but not limited to, the
26 costs of procuring power and energy demand-response resources
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1 under this Section and its costs for purchasing renewable
2 energy credits pursuant to subsection (c-5) of Section 1-75 of
3 the Illinois Power Agency Act. The utility shall file with the
4 initial procurement plan its proposed tariffs through which
5 its costs of procuring power that are incurred pursuant to a
6 Commission-approved procurement plan and those other costs
7 identified in this subsection (l), will be recovered. The
8 tariffs shall include a formula rate or charge designed to
9 pass through both the costs incurred by the utility in
10 procuring a supply of electric power and energy for the
11 applicable customer classes with no mark-up or return on the
12 price paid by the utility for that supply, plus any just and
13 reasonable costs that the utility incurs in arranging and
14 providing for the supply of electric power and energy. The
15 formula rate or charge shall also contain provisions that
16 ensure that its application does not result in over or under
17 recovery due to changes in customer usage and demand patterns,
18 and that provide for the correction, on at least an annual
19 basis, of any accounting errors that may occur. A utility
20 shall recover through the tariff all reasonable costs incurred
21 to implement or comply with any procurement plan that is
22 developed and put into effect pursuant to Section 1-75 of the
23 Illinois Power Agency Act and this Section, and for the
24 procurement of renewable energy credits pursuant to subsection
25 (c-5) of Section 1-75 of the Illinois Power Agency Act,
26 including any fees assessed by the Illinois Power Agency,
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1 costs associated with load balancing, and contingency plan
2 costs. The electric utility shall also recover its full costs
3 of procuring electric supply for which it contracted before
4 the effective date of this Section in conjunction with the
5 provision of full requirements service under fixed-price
6 bundled service tariffs subsequent to December 31, 2006. All
7 such costs shall be deemed to have been prudently incurred.
8 The pass-through tariffs that are filed and approved pursuant
9 to this Section shall not be subject to review under, or in any
10 way limited by, Section 16-111(i) of this Act. All of the costs
11 incurred by the electric utility associated with the purchase
12 of zero emission credits in accordance with subsection (d-5)
13 of Section 1-75 of the Illinois Power Agency Act, all costs
14 incurred by the electric utility associated with the purchase
15 of carbon mitigation credits in accordance with subsection
16 (d-10) of Section 1-75 of the Illinois Power Agency Act, and,
17 beginning June 1, 2017, all of the costs incurred by the
18 electric utility associated with the purchase of renewable
19 energy resources in accordance with Sections 1-56 and 1-75 of
20 the Illinois Power Agency Act, and all of the costs incurred by
21 the electric utility in purchasing renewable energy credits in
22 accordance with subsection (c-5) of Section 1-75 of the
23 Illinois Power Agency Act, shall be recovered through the
24 electric utility's tariffed charges applicable to all of its
25 retail customers, as specified in subsection (k) or subsection
26 (i-5), as applicable, of Section 16-108 of this Act, and shall
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1 not be recovered through the electric utility's tariffed
2 charges for electric power and energy supply to its eligible
3 retail customers.
4 (m) The Commission has the authority to adopt rules to
5 carry out the provisions of this Section. For the public
6 interest, safety, and welfare, the Commission also has
7 authority to adopt rules to carry out the provisions of this
8 Section on an emergency basis immediately following August 28,
9 2007 (the effective date of Public Act 95-481).
10 (n) Notwithstanding any other provision of this Act, any
11 affiliated electric utilities that submit a single procurement
12 plan covering their combined needs may procure for those
13 combined needs in conjunction with that plan, and may enter
14 jointly into power supply contracts, purchases, and other
15 procurement arrangements, and allocate capacity and energy and
16 cost responsibility therefor among themselves in proportion to
17 their requirements.
18 (o) On or before June 1 of each year, the Commission shall
19 hold an informal hearing for the purpose of receiving comments
20 on the prior year's procurement process and any
21 recommendations for change.
22 (p) An electric utility subject to this Section may
23 propose to invest, lease, own, or operate an electric
24 generation facility as part of its procurement plan, provided
25 the utility demonstrates that such facility is the least-cost
26 option to provide electric service to those retail customers
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1 included in the plan's electric supply service requirements.
2 If the facility is shown to be the least-cost option and is
3 included in a procurement plan prepared in accordance with
4 Section 1-75 of the Illinois Power Agency Act and this
5 Section, then the electric utility shall make a filing
6 pursuant to Section 8-406 of this Act, and may request of the
7 Commission any statutory relief required thereunder. If the
8 Commission grants all of the necessary approvals for the
9 proposed facility, such supply shall thereafter be considered
10 as a pre-existing contract under subsection (b) of this
11 Section. The Commission shall in any order approving a
12 proposal under this subsection specify how the utility will
13 recover the prudently incurred costs of investing in, leasing,
14 owning, or operating such generation facility through just and
15 reasonable rates charged to those retail customers included in
16 the plan's electric supply service requirements. Cost recovery
17 for facilities included in the utility's procurement plan
18 pursuant to this subsection shall not be subject to review
19 under or in any way limited by the provisions of Section
20 16-111(i) of this Act. Nothing in this Section is intended to
21 prohibit a utility from filing for a fuel adjustment clause as
22 is otherwise permitted under Section 9-220 of this Act.
23 (q) If the Illinois Power Agency filed with the
24 Commission, under Section 16-111.5 of this Act, its proposed
25 procurement plan for the period commencing June 1, 2017, and
26 the Commission has not yet entered its final order approving
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1 the plan on or before the effective date of this amendatory Act
2 of the 99th General Assembly, then the Illinois Power Agency
3 shall file a notice of withdrawal with the Commission, after
4 the effective date of this amendatory Act of the 99th General
5 Assembly, to withdraw the proposed procurement of renewable
6 energy resources to be approved under the plan, other than the
7 procurement of renewable energy credits from distributed
8 renewable energy generation devices using funds previously
9 collected from electric utilities' retail customers that take
10 service pursuant to electric utilities' hourly pricing tariff
11 or tariffs and, for an electric utility that serves less than
12 100,000 retail customers in the State, other than the
13 procurement of renewable energy credits from distributed
14 renewable energy generation devices. Upon receipt of the
15 notice, the Commission shall enter an order that approves the
16 withdrawal of the proposed procurement of renewable energy
17 resources from the plan. The initially proposed procurement of
18 renewable energy resources shall not be approved or be the
19 subject of any further hearing, investigation, proceeding, or
20 order of any kind.
21 This amendatory Act of the 99th General Assembly preempts
22 and supersedes any order entered by the Commission that
23 approved the Illinois Power Agency's procurement plan for the
24 period commencing June 1, 2017, to the extent it is
25 inconsistent with the provisions of this amendatory Act of the
26 99th General Assembly. To the extent any previously entered
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1 order approved the procurement of renewable energy resources,
2 the portion of that order approving the procurement shall be
3 void, other than the procurement of renewable energy credits
4 from distributed renewable energy generation devices using
5 funds previously collected from electric utilities' retail
6 customers that take service under electric utilities' hourly
7 pricing tariff or tariffs and, for an electric utility that
8 serves less than 100,000 retail customers in the State, other
9 than the procurement of renewable energy credits for
10 distributed 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
14 suppliers.
15 (a) Any alternative retail electric supplier must obtain a
16 certificate of service authority from the Commission in
17 accordance with this Section before serving any retail
18 customer or other user located in this State. An alternative
19 retail electric supplier may request, and the Commission may
20 grant, a certificate of service authority for the entire State
21 or for a specified geographic area of the State. A certificate
22 granted pursuant to this Section is not property, and the
23 grant of a certificate to an entity does not create a property
24 interest in the certificate. This Section does not diminish
25 the existing rights of a certificate holder to notice and
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1 hearing as proscribed by the Illinois Administrative Procedure
2 Act and in rules adopted by the Commission.
3 (b) An alternative retail electric supplier seeking a
4 certificate of service authority shall file with the
5 Commission a verified application containing information
6 showing that the applicant meets the requirements of this
7 Section. The alternative retail electric supplier shall
8 publish notice of its application in the official State
9 newspaper within 10 days following the date of its filing. No
10 later than 45 days after a complete application is properly
11 filed with the Commission, and such notice is published, the
12 Commission shall issue its order granting or denying the
13 application.
14 (c) An application for a certificate of service authority
15 shall identify the area or areas in which the applicant
16 intends to offer service and the types of services it intends
17 to offer. Applicants that seek to serve residential or small
18 commercial retail customers within a geographic area that is
19 smaller than an electric utility's service area shall submit
20 evidence demonstrating that the designation of this smaller
21 area does not violate Section 16-115A. An applicant that seeks
22 to serve residential or small commercial retail customers may
23 state in its application for certification any limitations
24 that will be imposed on the number of customers or maximum load
25 to be served.
26 (d) The Commission shall grant the application for a
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1 certificate of service authority if it makes the findings set
2 forth in this subsection based on the verified application and
3 such 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
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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;
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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
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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
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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
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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
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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
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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
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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
14 application in which the applicant fails to provide the
15 Commission with information sufficient for the Commission to
16 grant the application.
17 (d-5) (Blank).
18 (e) A retail customer that owns a cogeneration or
19 self-generation facility and that seeks certification only to
20 provide electric power and energy from such facility to retail
21 customers at separate locations which customers are both (i)
22 owned by, or a subsidiary or other corporate affiliate of,
23 such applicant and (ii) eligible for delivery services, shall
24 be granted a certificate of service authority upon filing an
25 application and notifying the Commission that it has entered
26 into an agreement with the relevant electric utilities
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1 pursuant to Section 16-118. Provided, however, that if the
2 retail customer owning such cogeneration or self-generation
3 facility would not be charged a transition charge due to the
4 exemption provided under subsection (f) of Section 16-108
5 prior to the certification, and the retail customers at
6 separate locations are taking delivery services in conjunction
7 with purchasing power and energy from the facility, the retail
8 customer on whose premises the facility is located shall not
9 thereafter be required to pay transition charges on the power
10 and energy that such retail customer takes from the facility.
11 (f) The Commission shall have the authority to promulgate
12 rules and regulations to carry out the provisions of this
13 Section. On or before May 1, 1999, the Commission shall adopt a
14 rule or rules applicable to the certification of those
15 alternative retail electric suppliers that seek to serve only
16 nonresidential retail customers with maximum electrical
17 demands of one megawatt or more which shall provide for (i)
18 expedited and streamlined procedures for certification of such
19 alternative retail electric suppliers and (ii) specific
20 criteria which, if met by any such alternative retail electric
21 supplier, shall constitute the demonstration of technical,
22 financial and managerial resources and abilities to provide
23 service required by paragraph (1) of subsection (d) of this
24 Section, such as a requirement to post a bond or letter of
25 credit, from a responsible surety or financial institution, of
26 sufficient size for the nature and scope of the services to be
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1 provided; demonstration of adequate insurance for the scope
2 and nature of the services to be provided; and experience in
3 providing similar services in other jurisdictions.
4 (g) An alternative retail electric supplier may seek
5 confidential treatment for the following information by filing
6 an affidavit with the Commission so long as the affidavit
7 meets 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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1 information for which confidential treatment is sought and
2 must clearly state that the affiant seeks confidential
3 treatment pursuant to this subsection (g) and the information
4 for which confidential treatment is sought must be clearly
5 identified on the confidential version of the document filed
6 with the Commission. The affidavit must be accompanied by a
7 "confidential" and a "public" version of the document or
8 documents containing the information for which confidential
9 treatment is sought.
10 If the alternative retail electric supplier has met the
11 affidavit requirements of this subsection (g), then the
12 Commission shall afford confidential treatment to the
13 information identified in the affidavit for a period of 2
14 years after the date the affidavit is received by the
15 Commission.
16 Nothing in this subsection (g) prevents an alternative
17 retail electric supplier from filing a petition with the
18 Commission seeking confidential treatment for information
19 beyond that identified in this subsection (g) or for
20 information contained in other reports or documents filed with
21 the Commission other than annual rate reports.
22 Nothing in this subsection (g) prevents the Commission, on
23 its own motion, or any party from filing a formal petition with
24 the Commission seeking to reconsider the conferring of
25 confidential status on an item of information afforded
26 confidential treatment pursuant to this subsection (g).
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1 The Commission, on its own motion, may at any time
2 initiate a docketed proceeding to investigate the continued
3 applicability of this subsection (g) to the information
4 contained in items (i), (ii), and (iii) of this subsection
5 (g). If, at the end of such investigation, the Commission
6 determines that a particular item of information should no
7 longer be eligible for the affidavit-based process outlined in
8 this subsection (g), the Commission may enter an order to
9 remove that item from the list of items eligible for the
10 process set forth in this subsection (g). Notwithstanding any
11 such order, in the event the Commission makes such a
12 determination, nothing in this subsection (g) prevents an
13 alternative retail electric supplier desiring confidential
14 treatment for such information from filing a formal petition
15 with the Commission seeking confidential treatment for such
16 information.
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
20 retail electric suppliers and electric utilities operating
21 outside their service territories.
22 (a) An alternative retail electric supplier shall be
23 responsible for procuring cost-effective renewable energy
24 resources as required under item (5) of subsection (d) of
25 Section 16-115 of this Act as outlined herein:
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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
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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
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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.
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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
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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
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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
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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
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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.
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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.
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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
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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
23 September 1, 2010 and by September 1 of each year thereafter,
24 prepare and submit to the Commission a report, in a format to
25 be specified by the Commission, that provides information
26 certifying compliance by the alternative retail electric
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1 supplier with this Section, including copies of all PJM-GATS
2 and M-RETS reports, and documentation relating to banking,
3 retiring renewable energy credits, and any other information
4 that the Commission determines necessary to ensure compliance
5 with this Section.
6 An alternative retail electric supplier may file
7 commercially or financially sensitive information or trade
8 secrets with the Commission as provided under the rules of the
9 Commission. To be filed confidentially, the information shall
10 be accompanied by an affidavit that sets forth both the
11 reasons for the confidentiality and a public synopsis of the
12 information.
13 (e-5) Each alternative retail electric supplier shall make
14 payment to an applicable electric utility for capacity,
15 receive transfers of capacity credits, timely report capacity
16 credits procured on its behalf to the applicable regional
17 transmission organization, and submit the capacity credits to
18 the applicable regional transmission organization under that
19 regional transmission organization's rules and procedures, in
20 all respects as set out in subsection (b-10) of Section
21 16-111.5. The Commission shall have authority to adopt rules
22 for the certification by alternative retail electric suppliers
23 of their ongoing compliance with the requirements in this
24 subsection.
25 (f) The Commission may initiate a contested case to review
26 allegations that the alternative retail electric supplier has
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1 violated this Section, including an order issued or rule
2 promulgated under this Section. In any such proceeding, the
3 alternative retail electric supplier shall have the burden of
4 proof. If the Commission finds, after notice and hearing, that
5 an alternative retail electric supplier has violated this
6 Section, then the Commission shall issue an order requiring
7 the 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
18 with the renewable energy resource portfolio requirement or
19 capacity portfolio requirement in this Section more than once
20 in a 5-year period, then the Commission shall revoke the
21 alternative electric supplier's certificate of service
22 authority. The Commission shall not accept an application for
23 a certificate of service authority from an alternative retail
24 electric supplier that has lost certification under this
25 subsection (f), or any corporate affiliate thereof, for at
26 least one year after the date of revocation.
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1 (g) All of the provisions of this Section apply to
2 electric utilities operating outside their service area except
3 under item (2) of subsection (a) of this Section the quantity
4 of renewable energy resources shall be measured as a
5 percentage of the actual amount of electricity
6 (megawatt-hours) supplied in the State outside of the
7 utility's service territory during the 12-month period June 1
8 through May 31, commencing June 1, 2009, and the comparable
9 12-month period in each year thereafter except as provided in
10 item (6) of subsection (a) of this Section.
11 If any such utility fails to procure the requisite
12 quantity of renewable energy resources by the annual deadline,
13 then the Commission shall require the utility to double the
14 alternative compliance payment that would otherwise be
15 required to bring the utility into compliance with this
16 Section.
17 If any such utility fails to comply with the renewable
18 energy resource portfolio requirement in this Section more
19 than once in a 5-year period, then the Commission shall order
20 the utility to cease all sales outside of the utility's
21 service territory for a period of at least one year.
22 (h) The provisions of this Section and the provisions of
23 subsection (d) of Section 16-115 of this Act relating to
24 procurement of renewable energy resources shall not apply to
25 an alternative retail electric supplier that operates a
26 combined heat and power system in this State or that has a
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1 corporate affiliate that operates such a combined heat and
2 power system in this State that supplies electricity primarily
3 to or for the benefit of: (i) facilities owned by the supplier,
4 its subsidiary, or other corporate affiliate; (ii) facilities
5 electrically integrated with the electrical system of
6 facilities owned by the supplier, its subsidiary, or other
7 corporate affiliate; or (iii) facilities that are adjacent to
8 the site on which the combined heat and power system is
9 located.
10 (i) The obligations of alternative retail electric
11 suppliers and electric utilities operating outside their
12 service territories to procure renewable energy resources,
13 make alternative compliance payments, and file annual reports,
14 and the obligations of the Commission to determine and post
15 alternative compliance payment rates, shall terminate after
16 May 31, 2019, provided that alternative retail electric
17 suppliers and electric utilities operating outside their
18 service territories shall be obligated to make all alternative
19 compliance payments that they were obligated to pay for
20 periods through and including May 31, 2019, but were not paid
21 as of that date. The Commission shall continue to enforce the
22 payment of unpaid alternative compliance payments in
23 accordance with subsections (f) and (g) of this Section. All
24 alternative compliance payments made after May 31, 2016 shall
25 be remitted to the applicable electric utility and used to
26 purchase renewable energy credits, in accordance with Section
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1 1-75 of the Illinois Power Agency Act.
2 This subsection (i) is intended to accommodate the
3 transition to the procurement of renewable energy resources
4 for all retail customers in the amounts specified under
5 subsection (c) of Section 1-75 of the Illinois Power Agency
6 Act and Section 16-111.5 of this Act, including but not
7 limited to the transition to a single charge applicable to all
8 retail customers to recover the costs of these resources. Each
9 alternative retail electric supplier shall certify in its
10 annual reports filed pursuant to subsection (e) of this
11 Section after May 31, 2019, that its retail customers are not
12 paying the costs of alternative compliance payments or
13 renewable energy resources that the alternative retail
14 electric supplier is not required to remit or purchase under
15 this Section. The Commission shall have the authority to
16 initiate an emergency rulemaking to adopt rules regarding such
17 certification.
18 (Source: P.A. 99-906, eff. 6-1-17.)
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1 INDEX
2 Statutes amended in order of appearance
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1 INDEX
2 Statutes amended in order of appearance
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