Illinois General Assembly - Full Text of SB3866
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Full Text of SB3866  102nd General Assembly

SB3866ham004 102ND GENERAL ASSEMBLY

Rep. Lawrence Walsh, Jr.

Filed: 4/7/2022

 

 


 

 


 
10200SB3866ham004LRB102 24630 LNS 38917 a

1
AMENDMENT TO SENATE BILL 3866

2    AMENDMENT NO. ______. Amend Senate Bill 3866 by replacing
3everything after the enacting clause with the following:
 
4
"Article 1.

 
5    Section 1-5. The Energy Transition Act is amended by
6changing Section 5-40 as follows:
 
7    (20 ILCS 730/5-40)
8    (Section scheduled to be repealed on September 15, 2045)
9    Sec. 5-40. Illinois Climate Works Preapprenticeship
10Program.
11    (a) Subject to appropriation, the Department shall
12develop, and through Regional Administrators administer, the
13Illinois Climate Works Preapprenticeship Program. The goal of
14the Illinois Climate Works Preapprenticeship Program is to
15create a network of hubs throughout the State that will

 

 

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1recruit, prescreen, and provide preapprenticeship skills
2training, for which participants may attend free of charge and
3receive a stipend, to create a qualified, diverse pipeline of
4workers who are prepared for careers in the construction and
5building trades and clean energy jobs opportunities therein.
6Upon completion of the Illinois Climate Works
7Preapprenticeship Program, the candidates will be connected to
8and prepared to successfully complete an apprenticeship
9program.
10    (b) Each Climate Works Hub that receives funding from the
11Energy Transition Assistance Fund shall provide an annual
12report to the Illinois Works Review Panel by April 1 of each
13calendar year. The annual report shall include the following
14information:
15        (1) a description of the Climate Works Hub's
16    recruitment, screening, and training efforts, including a
17    description of training related to construction and
18    building trades opportunities in clean energy jobs;
19        (2) the number of individuals who apply to,
20    participate in, and complete the Climate Works Hub's
21    program, broken down by race, gender, age, and veteran
22    status;
23        (3) the number of the individuals referenced in
24    paragraph (2) of this subsection who are initially
25    accepted and placed into apprenticeship programs in the
26    construction and building trades; and

 

 

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1        (4) the number of individuals referenced in paragraph
2    (2) of this subsection who remain in apprenticeship
3    programs in the construction and building trades or have
4    become journeymen one calendar year after their placement,
5    as referenced in paragraph (3) of this subsection.
6    (c) Subject to appropriation, the Department shall provide
7funding to 3 Climate Works Hubs throughout the State,
8including one to the Illinois Department of Transportation
9Region 1, one to the Illinois Department of Transportation
10Regions 2 and 3, and one to the Illinois Department of
11Transportation Regions 4 and 5. Climate Works Hubs shall be
12awarded grants in multi-year increments not to exceed 36
13months. Each grant shall come with a one year initial term,
14with the Department renewing each year for 2 additional years
15unless the grantee either declines to continue or fails to
16meet reasonable performance measures that consider
17apprenticeship programs timeframes. The Department shall
18initially select a community-based provider in each region and
19shall subsequently select a community-based provider in each
20region every 3 years. The Department may take into account
21experience and performance as a previous grantee of the
22Climate Works Hub as part of the selection criteria for
23subsequent years.
24    (d) Each Climate Works Hub that receives funding from the
25Energy Transition Assistance Fund shall: The Climate Works
26Hubs shall recruit, prescreen, and provide preapprenticeship

 

 

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1training to equity investment eligible persons. This training
2shall include information related to opportunities and
3certifications relevant to clean energy jobs in the
4construction and building trades.
5        (1) recruit, prescreen, and provide preapprenticeship
6    training to equity investment eligible persons;
7        (2) provide training information related to
8    opportunities and certifications relevant to clean energy
9    jobs in the construction and building trades; and
10        (3) provide preapprentices with stipends they receive
11    that may vary depending on the occupation the individual
12    is training for.
13    (d-5) Priority shall be given to Climate Works Hubs that
14have an agreement with North American Building Trades Unions
15(NABTU) to utilize the Multi-Craft Core Curriculum or
16successor curriculums.
17    (e) Funding for the Program is subject to appropriation
18from the Energy Transition Assistance Fund.
19    (f) The Department shall adopt any rules deemed necessary
20to implement this Section.
21(Source: P.A. 102-662, eff. 9-15-21.)
 
22    Section 1-10. The Public Utilities Act is amended by
23changing Sections 5-117, 8-218, 16-107.6, 16-108.5, and
2416-108.30 and by adding Section 16-111.11 as follows:
 

 

 

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1    (220 ILCS 5/5-117)
2    Sec. 5-117. Supplier diversity goals.
3    (a) The public policy of this State is to collaboratively
4work with companies that serve Illinois residents to improve
5their supplier diversity in a non-antagonistic manner.
6    (b) The Commission shall require all gas, electric, and
7water utilities companies with at least 100,000 customers
8under its authority, as well as suppliers of wind energy,
9solar energy, hydroelectricity, nuclear energy, and any other
10supplier of energy within this State, to submit an annual
11report by April 15, 2015 and every April 15 thereafter, in a
12searchable Adobe PDF format, on all procurement goals and
13actual spending for female-owned, minority-owned,
14veteran-owned, and small business enterprises in the previous
15calendar year. These goals shall be expressed as a percentage
16of the total work performed by the entity submitting the
17report, and the actual spending for all female-owned,
18minority-owned, veteran-owned, and small business enterprises
19shall also be expressed as a percentage of the total work
20performed by the entity submitting the report.
21    (c) Each participating company in its annual report shall
22include the following information:
23        (1) an explanation of the plan for the next year to
24    increase participation;
25        (2) an explanation of the plan to increase the goals;
26        (3) the areas of procurement each company shall be

 

 

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1    actively seeking more participation in the next year;
2        (3.5) a buying plan for the specific goods and
3    services the company intends to buy in the next 6 to 18
4    months, that is either (i) organized by and reported at
5    the level of each applicable North American Industry
6    Classification System code, (ii) provided using a method,
7    system, or description similar to the North American
8    Industry Classification System, or (iii) provided using
9    the major categories of goods and related services
10    utilized in the company's procurement system, and
11    including any procurement codes used by the company, to
12    assist entrepreneurs and diverse companies to understand
13    upcoming opportunities to work with the company, however,
14    a utility shall not be required to include
15    commercially-sensitive data, nonpublic procurement
16    information, or other information that could compromise a
17    utility's ability to negotiate the most advantageous price
18    or terms;
19        (4) an outline of the plan to alert and encourage
20    potential vendors in that area to seek business from the
21    company;
22        (5) an explanation of the challenges faced in finding
23    quality vendors and offer any suggestions for what the
24    Commission could do to be helpful to identify those
25    vendors;
26        (6) a list of the certifications the company

 

 

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1    recognizes;
2        (7) the point of contact for any potential vendor who
3    wishes to do business with the company and explain the
4    process for a vendor to enroll with the company as a
5    minority-owned, women-owned, or veteran-owned company; and
6        (8) any particular success stories to encourage other
7    companies to emulate best practices.
8    (d) Each annual report shall include as much
9State-specific data as possible. If the submitting entity does
10not submit State-specific data, then the company shall include
11any national data it does have and explain why it could not
12submit State-specific data and how it intends to do so in
13future reports, if possible.
14    (e) Each annual report shall include the rules,
15regulations, and definitions used for the procurement goals in
16the company's annual report.
17    (f) The Commission and all participating entities shall
18hold an annual workshop open to the public in 2015 and every
19year thereafter on the state of supplier diversity to
20collaboratively seek solutions to structural impediments to
21achieving stated goals, including testimony from each
22participating entity as well as subject matter experts and
23advocates. The Commission shall publish a database on its
24website of the point of contact for each participating entity
25for supplier diversity, along with a list of certifications
26each company recognizes from the information submitted in each

 

 

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1annual report. The Commission shall publish each annual report
2on its website and shall maintain each annual report for at
3least 5 years.
4(Source: P.A. 102-558, eff. 8-20-21; 102-662, eff. 9-15-21;
5102-673, eff. 11-30-21.)
 
6    (220 ILCS 5/8-218)
7    Sec. 8-218. Utility-scale pilot projects.
8    (a) Electric utilities serving greater than 500,000
9customers but less than 3,000,000 customers may propose, plan
10for, construct, install, control, own, manage, or operate up
11to 2 pilot projects consisting of utility-scale photovoltaic
12energy generation facilities. A pilot project may consist of
13photovoltaic energy generation facilities located on one or
14more sites and may be installed or constructed in phases.
15Energy storage facilities that are planned for, constructed,
16installed, controlled, owned, managed, or operated may be
17constructed in connection with the photovoltaic electricity
18generation pilot projects.
19    (b) Pilot projects shall be sited in equity investment
20eligible communities in or near the towns of Peoria and East
21St. Louis and must result in economic benefits for the members
22of the communities in which the project will be located. The
23amount paid per pilot project with or without energy storage
24facilities cannot exceed $20,000,000. The electric utility's
25costs of planning for, constructing, installing, controlling,

 

 

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1owning, managing, or operating the photovoltaic electricity
2generation facilities and energy storage facilities may be
3recovered, on a kilowatt hour basis, via an automatic
4adjustment clause tariff applicable to all retail customers,
5with the tariff to be approved by the Commission after
6opportunity for review, and with an annual reconciliation
7component; and for purposes of cost recovery, the photovoltaic
8electricity production facilities may be treated as regulatory
9assets, using the same ratemaking treatment in paragraph (1)
10of subsection (h) of Section 16-107.6 of this Act, provided:
11(1) the Commission shall have the authority to determine the
12reasonableness of the costs of the facilities, and (2) any
13monetary value of power and energy from the facilities shall
14be credited against the delivery services revenue requirement.
15    (c) Any electric utility seeking to propose, plan for,
16construct, install, control, own, manage, or operate a pilot
17project pursuant to this Section must commit to using a
18diverse and equitable workforce and a diverse set of
19contractors, including minority-owned businesses,
20disadvantaged businesses, trade unions, graduates of any
21workforce training programs established by this amendatory Act
22of the 102nd General Assembly, and small businesses. An
23electric utility must comply with the equity commitment
24requirements in subsection (c-10) of Section 1-75 of the
25Illinois Power Agency Act. The electric utility must certify
26that not less than the prevailing wage will be paid to

 

 

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1employees engaged in construction activities associated with
2the pilot project. The electric utility must file a project
3labor agreement, as defined in the Illinois Power Agency Act,
4with the Commission prior to constructing, installing,
5controlling, or owning a pilot project authorized by this
6Section.
7(Source: P.A. 102-662, eff. 9-15-21.)
 
8    (220 ILCS 5/16-107.6)
9    Sec. 16-107.6. Distributed generation rebate.
10    (a) In this Section:
11    "Additive services" means the services that distributed
12energy resources provide to the energy system and society that
13are not (1) already included in the base rebates for
14system-wide grid services; or (2) otherwise already
15compensated. Additive services may reflect, but shall not be
16limited to, any geographic, time-based, performance-based, and
17other benefits of distributed energy resources, as well as the
18present and future technological capabilities of distributed
19energy resources and present and future grid needs.
20    "Distributed energy resource" means a wide range of
21technologies that are located on the customer side of the
22customer's electric meter, including, but not limited to,
23distributed generation, energy storage, electric vehicles, and
24demand response technologies.
25    "Energy storage system" means commercially available

 

 

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1technology that is capable of absorbing energy and storing it
2for a period of time for use at a later time, including, but
3not limited to, electrochemical, thermal, and
4electromechanical technologies, and may be interconnected
5behind the customer's meter or interconnected behind its own
6meter.
7    "Smart inverter" means a device that converts direct
8current into alternating current and meets the IEEE 1547-2018
9equipment standards. Until devices that meet the IEEE
101547-2018 standard are available, devices that meet the UL
111741 SA standard are acceptable.
12    "Subscriber" has the meaning set forth in Section 1-10 of
13the Illinois Power Agency Act.
14    "Subscription" has the meaning set forth in Section 1-10
15of the Illinois Power Agency Act.
16    "System-wide grid services" means the benefits that a
17distributed energy resource provides to the distribution grid
18for a period of no less than 25 years. System-wide grid
19services do not vary by location, time, or the performance
20characteristics of the distributed energy resource.
21System-wide grid services include, but are not limited to,
22avoided or deferred distribution capacity costs, resilience
23and reliability benefits, avoided or deferred distribution
24operation and maintenance costs, distribution voltage and
25power quality benefits, and line loss reductions.
26    "Threshold date" means December 31, 2024 or the date on

 

 

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1which the utility's tariff or tariffs setting the new
2compensation values established under subsection (e) take
3effect, whichever is later.
4    (b) An electric utility that serves more than 200,000
5customers in the State shall file a petition with the
6Commission requesting approval of the utility's tariff to
7provide a rebate to the owner or operator of distributed
8generation, including third-party owned systems, that meets
9the following criteria:
10        (1) has a nameplate generating capacity no greater
11    than 5,000 kilowatts and is primarily used to offset a
12    customer's electricity load;
13        (2) is located on the customer's side of the billing
14    meter and for the customer's own use;
15        (3) is interconnected to electric distribution
16    facilities owned by the electric utility under rules
17    adopted by the Commission by means of the inverter or
18    smart inverter required by this Section, as applicable.
19    For purposes of this Section, "distributed generation"
20shall satisfy the definition of distributed renewable energy
21generation device set forth in Section 1-10 of the Illinois
22Power Agency Act to the extent such definition is consistent
23with the requirements of this Section.
24    In addition, any new photovoltaic distributed generation
25that is installed after June 1, 2017 (the effective date of
26Public Act 99-906) must be installed by a qualified person, as

 

 

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1defined by subsection (i) of Section 1-56 of the Illinois
2Power Agency Act.
3    The tariff shall include a base rebate that compensates
4distributed generation for the system-wide grid services
5associated with distributed generation and, after the
6proceeding described in subsection (e) of this Section, an
7additional payment or payments for the additive services. The
8tariff shall provide that the smart inverter associated with
9the distributed generation shall provide autonomous response
10to grid conditions through its default settings as approved by
11the Commission. Default settings may not be changed after the
12execution of the interconnection agreement except by mutual
13agreement between the utility and the owner or operator of the
14distributed generation. Nothing in this Section shall negate
15or supersede Institute of Electrical and Electronics Engineers
16equipment standards or other similar standards or
17requirements. The tariff shall not limit the ability of the
18smart inverter or other distributed energy resource to provide
19wholesale market products such as regulation, demand response,
20or other services, or limit the ability of the owner of the
21smart inverter or the other distributed energy resource to
22receive compensation for providing those wholesale market
23products or services.
24    (b-5) Within 30 days after the effective date of this
25amendatory Act of the 102nd General Assembly, each electric
26public utility with 3,000,000 or more retail customers shall

 

 

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1file a tariff with the Commission that further compensates any
2retail customer that installs or has installed photovoltaic
3facilities paired with energy storage facilities on or
4adjacent to its premises for the benefits the facilities
5provide to the distribution grid. The tariff shall provide
6that, in addition to the other rebates identified in this
7Section, the electric utility shall rebate to such retail
8customer (i) the previously incurred and future costs of
9installing interconnection facilities and related
10infrastructure to enable full participation in the PJM
11Interconnection, LLC or its successor organization frequency
12regulation market; and (ii) all wholesale demand charges
13incurred after the effective date of this amendatory Act of
14the 102nd General Assembly. The Commission shall approve, or
15approve with modification, the tariff within 120 days after
16the utility's filing.
17    (c) The proposed tariff authorized by subsection (b) of
18this Section shall include the following participation terms
19for rebates to be applied under this Section for distributed
20generation that satisfies the criteria set forth in subsection
21(b) of this Section:
22        (1) The owner or operator of distributed generation
23    that services customers not eligible for net metering
24    under subsection (d), (d-5), or (e) of Section 16-107.5 of
25    this Act may apply for a rebate as provided for in this
26    Section. Until the threshold date, the value of the rebate

 

 

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

 

 

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1    threshold date, the value of the base rebate shall be $300
2    per kilowatt of nameplate generating capacity, measured as
3    nominal DC power output, of the distributed generation.
4    The owner or operator of distributed generation that,
5    before the threshold date, is eligible for net metering
6    under subsection (d), (d-5), or (e) of Section 16-107.5 of
7    this Act may apply for a base rebate for an energy storage
8    device that uses the same smart inverter as the
9    distributed generation, regardless of whether the
10    distributed generation applies for a rebate for the
11    distributed generation device. The energy storage system
12    shall be separately compensated at a base payment of $300
13    per kilowatt-hour of nameplate capacity. Any distributed
14    generation device that is compensated for storage in this
15    subsection (2) before the threshold date shall participate
16    in a peak time rebate program, hourly pricing program, or
17    time-of-use rate program offered by the applicable
18    electric utility. After the threshold date, the value of
19    the base rebate and additional compensation for any
20    additive services shall be as determined by the Commission
21    in the proceeding described in subsection (e) of this
22    Section, provided that, prior to December 31, 2029, the
23    value of the base rebate for system-wide services shall
24    not be lower than $300 per kilowatt of nameplate
25    generating capacity of distributed generation, after which
26    it shall not be lower than $250 per kilowatt of nameplate

 

 

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1    capacity.
2        (3) Upon approval of a rebate application submitted
3    under this subsection (c), the retail customer shall no
4    longer be entitled to receive any delivery service credits
5    for the excess electricity generated by its facility and
6    shall be subject to the provisions of subsection (n) of
7    Section 16-107.5 of this Act unless the owner or operator
8    receives a rebate only for an energy storage device and
9    not for the distributed generation device.
10        (4) To be eligible for a rebate described in this
11    subsection (c), the owner or operator of the distributed
12    generation must have a smart inverter installed and in
13    operation on the distributed generation.
14    (d) The Commission shall review the proposed tariff
15authorized by subsection (b) of this Section and may make
16changes to the tariff that are consistent with this Section
17and with the Commission's authority under Article IX of this
18Act, subject to notice and hearing. Following notice and
19hearing, the Commission shall issue an order approving, or
20approving with modification, such tariff no later than 240
21days after the utility files its tariff. Upon the effective
22date of this amendatory Act of the 102nd General Assembly, an
23electric utility shall file a petition with the Commission to
24amend and update any existing tariffs to comply with
25subsections (b) and (c).
26    (e) By no later than June 30, 2023, the Commission shall

 

 

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1open an independent, statewide investigation into the value
2of, and compensation for, distributed energy resources. The
3Commission shall conduct the investigation, but may arrange
4for experts or consultants independent of the utilities and
5selected by the Commission to assist with the investigation.
6The cost of the investigation shall be shared by the utilities
7filing tariffs under subsection (b) of this Section but may be
8recovered as an expense through normal ratemaking procedures.
9        (1) The Commission shall ensure that the investigation
10    includes, at minimum, diverse sets of stakeholders; a
11    review of best practices in calculating the value of
12    distributed energy resource benefits; a review of the full
13    value of the distributed energy resources and the manner
14    in which each component of that value is or is not
15    otherwise compensated; and assessments of how the value of
16    distributed energy resources may evolve based on the
17    present and future technological capabilities of
18    distributed energy resources and based on present and
19    future grid needs.
20        (2) The Commission's final order concluding this
21    investigation shall establish an annual process and
22    formula for the compensation of distributed generation and
23    energy storage systems, and an initial set of inputs for
24    that formula. The Commission's final order concluding this
25    investigation shall establish base rebates that compensate
26    distributed generation, community renewable generation

 

 

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1    projects and energy storage systems for the system-wide
2    grid services that they provide. Those base rebate values
3    shall be consistent across the state, and shall not vary
4    by customer, customer class, customer location, or any
5    other variable. With respect to rebates for distributed
6    generation or community renewable generation projects,
7    that rebate shall not be lower than $250 per kilowatt of
8    nameplate generating capacity of the distributed
9    generation or community renewable generation project. The
10    Commission's final order concluding this proceeding shall
11    also direct the utilities to update the formula, on an
12    annual basis, with inputs derived from their integrated
13    grid plans developed pursuant to Section 16-105.17. The
14    base rebate shall be updated annually based on the annual
15    updates to the formula inputs, but, with respect to
16    rebates for distributed generation or community renewable
17    generation projects, shall be no lower than $250 per
18    kilowatt of nameplate generating capacity of the
19    distributed generation or community renewable generation
20    project.
21        (3) The Commission shall also determine, as a part of
22    its investigation under this subsection, whether
23    distributed energy resources can provide any additive
24    services. Those additive services may include services
25    that are provided through utility-controlled responses to
26    grid conditions. If the Commission determines that

 

 

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1    distributed energy resources can provide additive grid
2    services, the Commission shall determine the terms and
3    conditions for the operation and compensation of those
4    services. That compensation shall be above and beyond the
5    base rebate that the distributed energy generation,
6    community renewable generation project and energy storage
7    system receives. Compensation for additive services may
8    vary by location, time, performance characteristics,
9    technology types, or other variables.
10        (4) The Commission shall ensure that compensation for
11    distributed energy resources, including base rebates and
12    any payments for additive services, shall reflect all
13    reasonably known and measurable values of the distributed
14    generation over its full expected useful life.
15    Compensation for additive services shall reflect, but
16    shall not be limited to, any geographic, time-based,
17    performance-based, and other benefits of distributed
18    generation, as well as the present and future
19    technological capabilities of distributed energy resources
20    and present and future grid needs.
21        (5) The Commission shall consider the electric
22    utility's integrated grid plan developed pursuant to
23    Section 16-105.17 of this Act to help identify the value
24    of distributed energy resources for the purpose of
25    calculating the compensation described in this subsection.
26        (6) The Commission shall determine additional

 

 

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1    compensation for distributed energy resources that creates
2    savings and value on the distribution system by being
3    co-located or in close proximity to electric vehicle
4    charging infrastructure in use by medium-duty and
5    heavy-duty vehicles, primarily serving environmental
6    justice communities, as outlined in the utility integrated
7    grid planning process under Section 16-105.17 of this Act.
8    No later than 60 days after the Commission enters its
9final order under this subsection (e), each utility shall file
10its updated tariff or tariffs in compliance with the order,
11including new tariffs for the recovery of costs incurred under
12this subsection (e) that shall provide for volumetric-based
13cost recovery, and the Commission shall approve, or approve
14with modification, the tariff or tariffs within 240 days after
15the utility's filing.
16    (f) Notwithstanding any provision of this Act to the
17contrary, the owner or operator of a community renewable
18generation project as defined in Section 1-10 of the Illinois
19Power Agency Act shall also be eligible to apply for the rebate
20described in this Section. The owner or operator of the
21community renewable generation project may apply for a rebate
22only if the owner or operator, or previous owner or operator,
23of the community renewable generation project has not already
24submitted an application, and, regardless of whether the
25subscriber is a residential or non-residential customer, may
26be allowed the amount identified in paragraph (1) of

 

 

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1subsection (c) applicable on the date that the application is
2submitted.
3    (g) The owner of the distributed generation or community
4renewable generation project may apply for the rebate or
5rebates approved under this Section at the time of execution
6of an interconnection agreement with the distribution utility
7and shall receive the value available at that time of
8execution of the interconnection agreement, provided the
9project reaches mechanical completion within 24 months after
10execution of the interconnection agreement. If the project has
11not reached mechanical completion within 24 months after
12execution, the owner may reapply for the rebate or rebates
13approved under this Section available at the time of
14application and shall receive the value available at the time
15of application. The utility shall issue the rebate no later
16than 60 days after the project is energized. In the event the
17application is incomplete or the utility is otherwise unable
18to calculate the payment based on the information provided by
19the owner, the utility shall issue the payment no later than 60
20days after the application is complete or all requested
21information is received.
22    (h) An electric utility shall recover from its retail
23customers all of the costs of the rebates made under a tariff
24or tariffs approved under subsection (d) of this Section,
25including, but not limited to, the value of the rebates and all
26costs incurred by the utility to comply with and implement

 

 

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1subsections (b) and (c) of this Section, but not including
2costs incurred by the utility to comply with and implement
3subsection (e) of this Section, consistent with the following
4provisions:
5        (1) The utility shall defer the full amount of its
6    costs as a regulatory asset. The total costs deferred as a
7    regulatory asset shall be amortized over a 15-year period.
8    The unamortized balance shall be recognized as of December
9    31 for a given year. The utility shall also earn a return
10    on the total of the unamortized balance of the regulatory
11    assets, less any deferred taxes related to the unamortized
12    balance, at an annual rate equal to the utility's weighted
13    average cost of capital that includes, based on a year-end
14    capital structure, the utility's actual cost of debt for
15    the applicable calendar year and a cost of equity, which
16    shall be calculated as the sum of (i) the average for the
17    applicable calendar year of the monthly average yields of
18    30-year U.S. Treasury bonds published by the Board of
19    Governors of the Federal Reserve System in its weekly H.15
20    Statistical Release or successor publication; and (ii) 580
21    basis points, including a revenue conversion factor
22    calculated to recover or refund all additional income
23    taxes that may be payable or receivable as a result of that
24    return.
25        When an electric utility creates a regulatory asset
26    under the provisions of this paragraph (1) of subsection

 

 

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1    (h), the costs are recovered over a period during which
2    customers also receive a benefit, which is in the public
3    interest. Accordingly, it is the intent of the General
4    Assembly that an electric utility that elects to create a
5    regulatory asset under the provisions of this paragraph
6    (1) shall recover all of the associated costs, including,
7    but not limited to, its cost of capital as set forth in
8    this paragraph (1). After the Commission has approved the
9    prudence and reasonableness of the costs that comprise the
10    regulatory asset, the electric utility shall be permitted
11    to recover all such costs, and the value and
12    recoverability through rates of the associated regulatory
13    asset shall not be limited, altered, impaired, or reduced.
14    To enable the financing of the incremental capital
15    expenditures, including regulatory assets, for electric
16    utilities that serve less than 3,000,000 retail customers
17    but more than 500,000 retail customers in the State, the
18    utility's actual year-end capital structure that includes
19    a common equity ratio, excluding goodwill, of up to and
20    including 50% of the total capital structure shall be
21    deemed reasonable and used to set rates.
22        (2) The utility, at its election, may recover all of
23    the costs as part of a filing for a general increase in
24    rates under Article IX of this Act, as part of an annual
25    filing to update a performance-based formula rate under
26    subsection (d) of Section 16-108.5 of this Act, or through

 

 

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

 

 

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1    an order approving, or approving with modification, such
2    tariff no later than 240 days after the utility files its
3    tariff.
4    (i) An electric utility shall recover from its retail
5customers, on a volumetric basis, all of the costs of the
6rebates made under a tariff or tariffs placed into effect
7under subsection (e) of this Section, including, but not
8limited to, the value of the rebates and all costs incurred by
9the utility to comply with and implement subsection (e) of
10this Section, consistent with the following provisions:
11        (1) The utility may defer a portion of its costs as a
12    regulatory asset. The Commission shall determine the
13    portion that may be appropriately deferred as a regulatory
14    asset. Factors that the Commission shall consider in
15    determining the portion of costs that shall be deferred as
16    a regulatory asset include, but are not limited to: (i)
17    whether and the extent to which a cost effectively
18    deferred or avoided other distribution system operating
19    costs or capital expenditures; (ii) the extent to which a
20    cost provides environmental benefits; (iii) the extent to
21    which a cost improves system reliability or resilience;
22    (iv) the electric utility's distribution system plan
23    developed pursuant to Section 16-105.17 of this Act; (v)
24    the extent to which a cost advances equity principles; and
25    (vi) such other factors as the Commission deems
26    appropriate. The remainder of costs shall be deemed an

 

 

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1    operating expense and shall be recoverable if found
2    prudent and reasonable by the Commission.
3        The total costs deferred as a regulatory asset shall
4    be amortized over a 15-year period. The unamortized
5    balance shall be recognized as of December 31 for a given
6    year. The utility shall also earn a return on the total of
7    the unamortized balance of the regulatory assets, less any
8    deferred taxes related to the unamortized balance, at an
9    annual rate equal to the utility's weighted average cost
10    of capital that includes, based on a year-end capital
11    structure, the utility's actual cost of debt for the
12    applicable calendar year and a cost of equity, which shall
13    be calculated as the sum of: (I) the average for the
14    applicable calendar year of the monthly average yields of
15    30-year U.S. Treasury bonds published by the Board of
16    Governors of the Federal Reserve System in its weekly H.15
17    Statistical Release or successor publication; and (II) 580
18    basis points, including a revenue conversion factor
19    calculated to recover or refund all additional income
20    taxes that may be payable or receivable as a result of that
21    return.
22        (2) The utility may recover all of the costs through
23    an automatic adjustment clause tariff, on a volumetric
24    basis. The utility may file its proposed cost-recovery
25    tariff together with the tariff it files under subsection
26    (e) of this Section or at a later time. The proposed tariff

 

 

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1    shall provide for an annual reconciliation, less any
2    deferred taxes related to the reconciliation, with
3    interest at an annual rate of return equal to the
4    utility's weighted average cost of capital as calculated
5    under paragraph (1) of this subsection (i), including a
6    revenue conversion factor calculated to recover or refund
7    all additional income taxes that may be payable or
8    receivable as a result of that return, of the revenue
9    requirement reflected in rates for each calendar year,
10    beginning with the calendar year in which the utility
11    files its automatic adjustment clause tariff under this
12    subsection (i), with what the revenue requirement would
13    have been had the actual cost information for the
14    applicable calendar year been available at the filing
15    date. The Commission shall review the proposed tariff and
16    may make changes to the tariff that are consistent with
17    this Section and with the Commission's authority under
18    Article IX of this Act, subject to notice and hearing.
19    Following notice and hearing, the Commission shall issue
20    an order approving, or approving with modification, such
21    tariff no later than 240 days after the utility files its
22    tariff.
23    (j) No later than 90 days after the Commission enters an
24order, or order on rehearing, whichever is later, approving an
25electric utility's proposed tariff under this Section, the
26electric utility shall provide notice of the availability of

 

 

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1rebates under this Section.
2(Source: P.A. 102-662, eff. 9-15-21.)
 
3    (220 ILCS 5/16-108.5)
4    Sec. 16-108.5. Infrastructure investment and
5modernization; regulatory reform.
6    (a) (Blank).
7    (b) For purposes of this Section, "participating utility"
8means an electric utility or a combination utility serving
9more than 1,000,000 customers in Illinois that voluntarily
10elects and commits to undertake (i) the infrastructure
11investment program consisting of the commitments and
12obligations described in this subsection (b) and (ii) the
13customer assistance program consisting of the commitments and
14obligations described in subsection (b-10) of this Section,
15notwithstanding any other provisions of this Act and without
16obtaining any approvals from the Commission or any other
17agency other than as set forth in this Section, regardless of
18whether any such approval would otherwise be required.
19"Combination utility" means a utility that, as of January 1,
202011, provided electric service to at least one million retail
21customers in Illinois and gas service to at least 500,000
22retail customers in Illinois. A participating utility shall
23recover the expenditures made under the infrastructure
24investment program through the ratemaking process, including,
25but not limited to, the performance-based formula rate and

 

 

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1process set forth in this Section.
2    During the infrastructure investment program's peak
3program year, a participating utility other than a combination
4utility shall create 2,000 full-time equivalent jobs in
5Illinois, and a participating utility that is a combination
6utility shall create 450 full-time equivalent jobs in Illinois
7related to the provision of electric service. These jobs shall
8include direct jobs, contractor positions, and induced jobs,
9but shall not include any portion of a job commitment, not
10specifically contingent on an amendatory Act of the 97th
11General Assembly becoming law, between a participating utility
12and a labor union that existed on December 30, 2011 (the
13effective date of Public Act 97-646) and that has not yet been
14fulfilled. A portion of the full-time equivalent jobs created
15by each participating utility shall include incremental
16personnel hired subsequent to December 30, 2011 (the effective
17date of Public Act 97-646). For purposes of this Section,
18"peak program year" means the consecutive 12-month period with
19the highest number of full-time equivalent jobs that occurs
20between the beginning of investment year 2 and the end of
21investment year 4.
22    A participating utility shall meet one of the following
23commitments, as applicable:
24        (1) Beginning no later than 180 days after a
25    participating utility other than a combination utility
26    files a performance-based formula rate tariff pursuant to

 

 

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1    subsection (c) of this Section, or, beginning no later
2    than January 1, 2012 if such utility files such
3    performance-based formula rate tariff within 14 days of
4    October 26, 2011 (the effective date of Public Act
5    97-616), the participating utility shall, except as
6    provided in subsection (b-5):
7            (A) over a 5-year period, invest an estimated
8        $1,300,000,000 in electric system upgrades,
9        modernization projects, and training facilities,
10        including, but not limited to:
11                (i) distribution infrastructure improvements
12            totaling an estimated $1,000,000,000, including
13            underground residential distribution cable
14            injection and replacement and mainline cable
15            system refurbishment and replacement projects;
16                (ii) training facility construction or upgrade
17            projects totaling an estimated $10,000,000,
18            provided that, at a minimum, one such facility
19            shall be located in a municipality having a
20            population of more than 2 million residents and
21            one such facility shall be located in a
22            municipality having a population of more than
23            150,000 residents but fewer than 170,000
24            residents; any such new facility located in a
25            municipality having a population of more than 2
26            million residents must be designed for the purpose

 

 

10200SB3866ham004- 32 -LRB102 24630 LNS 38917 a

1            of obtaining, and the owner of the facility shall
2            apply for, certification under the United States
3            Green Building Council's Leadership in Energy
4            Efficiency Design Green Building Rating System;
5                (iii) wood pole inspection, treatment, and
6            replacement programs;
7                (iv) an estimated $200,000,000 for reducing
8            the susceptibility of certain circuits to
9            storm-related damage, including, but not limited
10            to, high winds, thunderstorms, and ice storms;
11            improvements may include, but are not limited to,
12            overhead to underground conversion and other
13            engineered outcomes for circuits; the
14            participating utility shall prioritize the
15            selection of circuits based on each circuit's
16            historical susceptibility to storm-related damage
17            and the ability to provide the greatest customer
18            benefit upon completion of the improvements; to be
19            eligible for improvement, the participating
20            utility's ability to maintain proper tree
21            clearances surrounding the overhead circuit must
22            not have been impeded by third parties; and
23            (B) over a 10-year period, invest an estimated
24        $1,300,000,000 to upgrade and modernize its
25        transmission and distribution infrastructure and in
26        Smart Grid electric system upgrades, including, but

 

 

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1        not limited to:
2                (i) additional smart meters;
3                (ii) distribution automation;
4                (iii) associated cyber secure data
5            communication network; and
6                (iv) substation micro-processor relay
7            upgrades.
8        (2) Beginning no later than 180 days after a
9    participating utility that is a combination utility files
10    a performance-based formula rate tariff pursuant to
11    subsection (c) of this Section, or, beginning no later
12    than January 1, 2012 if such utility files such
13    performance-based formula rate tariff within 14 days of
14    October 26, 2011 (the effective date of Public Act
15    97-616), the participating utility shall, except as
16    provided in subsection (b-5):
17            (A) over a 10-year period, invest an estimated
18        $265,000,000 in electric system upgrades,
19        modernization projects, and training facilities,
20        including, but not limited to:
21                (i) distribution infrastructure improvements
22            totaling an estimated $245,000,000, which may
23            include bulk supply substations, transformers,
24            reconductoring, and rebuilding overhead
25            distribution and sub-transmission lines,
26            underground residential distribution cable

 

 

10200SB3866ham004- 34 -LRB102 24630 LNS 38917 a

1            injection and replacement and mainline cable
2            system refurbishment and replacement projects;
3                (ii) training facility construction or upgrade
4            projects totaling an estimated $1,000,000; any
5            such new facility must be designed for the purpose
6            of obtaining, and the owner of the facility shall
7            apply for, certification under the United States
8            Green Building Council's Leadership in Energy
9            Efficiency Design Green Building Rating System;
10            and
11                (iii) wood pole inspection, treatment, and
12            replacement programs; and
13            (B) over a 10-year period, invest an estimated
14        $360,000,000 to upgrade and modernize its transmission
15        and distribution infrastructure and in Smart Grid
16        electric system upgrades, including, but not limited
17        to:
18                (i) additional smart meters;
19                (ii) distribution automation;
20                (iii) associated cyber secure data
21            communication network; and
22                (iv) substation micro-processor relay
23            upgrades.
24    For purposes of this Section, "Smart Grid electric system
25upgrades" shall have the meaning set forth in subsection (a)
26of Section 16-108.6 of this Act.

 

 

10200SB3866ham004- 35 -LRB102 24630 LNS 38917 a

1    The investments in the infrastructure investment program
2described in this subsection (b) shall be incremental to the
3participating utility's annual capital investment program, as
4defined by, for purposes of this subsection (b), the
5participating utility's average capital spend for calendar
6years 2008, 2009, and 2010 as reported in the applicable
7Federal Energy Regulatory Commission (FERC) Form 1; provided
8that where one or more utilities have merged, the average
9capital spend shall be determined using the aggregate of the
10merged utilities' capital spend reported in FERC Form 1 for
11the years 2008, 2009, and 2010. A participating utility may
12add reasonable construction ramp-up and ramp-down time to the
13investment periods specified in this subsection (b). For each
14such investment period, the ramp-up and ramp-down time shall
15not exceed a total of 6 months.
16    Within 60 days after filing a tariff under subsection (c)
17of this Section, a participating utility shall submit to the
18Commission its plan, including scope, schedule, and staffing,
19for satisfying its infrastructure investment program
20commitments pursuant to this subsection (b). The submitted
21plan shall include a schedule and staffing plan for the next
22calendar year. The plan shall also include a plan for the
23creation, operation, and administration of a Smart Grid test
24bed as described in subsection (c) of Section 16-108.8. The
25plan need not allocate the work equally over the respective
26periods, but should allocate material increments throughout

 

 

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1such periods commensurate with the work to be undertaken. No
2later than April 1 of each subsequent year, the utility shall
3submit to the Commission a report that includes any updates to
4the plan, a schedule for the next calendar year, the
5expenditures made for the prior calendar year and
6cumulatively, and the number of full-time equivalent jobs
7created for the prior calendar year and cumulatively. If the
8utility is materially deficient in satisfying a schedule or
9staffing plan, then the report must also include a corrective
10action plan to address the deficiency. The fact that the plan,
11implementation of the plan, or a schedule changes shall not
12imply the imprudence or unreasonableness of the infrastructure
13investment program, plan, or schedule. Further, no later than
1445 days following the last day of the first, second, and third
15quarters of each year of the plan, a participating utility
16shall submit to the Commission a verified quarterly report for
17the prior quarter that includes (i) the total number of
18full-time equivalent jobs created during the prior quarter,
19(ii) the total number of employees as of the last day of the
20prior quarter, (iii) the total number of full-time equivalent
21hours in each job classification or job title, (iv) the total
22number of incremental employees and contractors in support of
23the investments undertaken pursuant to this subsection (b) for
24the prior quarter, and (v) any other information that the
25Commission may require by rule.
26    With respect to the participating utility's peak job

 

 

10200SB3866ham004- 37 -LRB102 24630 LNS 38917 a

1commitment, if, after considering the utility's corrective
2action plan and compliance thereunder, the Commission enters
3an order finding, after notice and hearing, that a
4participating utility did not satisfy its peak job commitment
5described in this subsection (b) for reasons that are
6reasonably within its control, then the Commission shall also
7determine, after consideration of the evidence, including, but
8not limited to, evidence submitted by the Department of
9Commerce and Economic Opportunity and the utility, the
10deficiency in the number of full-time equivalent jobs during
11the peak program year due to such failure. The Commission
12shall notify the Department of any proceeding that is
13initiated pursuant to this paragraph. For each full-time
14equivalent job deficiency during the peak program year that
15the Commission finds as set forth in this paragraph, the
16participating utility shall, within 30 days after the entry of
17the Commission's order, pay $6,000 to a fund for training
18grants administered under Section 605-800 of the Department of
19Commerce and Economic Opportunity Law, which shall not be a
20recoverable expense.
21    With respect to the participating utility's investment
22amount commitments, if, after considering the utility's
23corrective action plan and compliance thereunder, the
24Commission enters an order finding, after notice and hearing,
25that a participating utility is not satisfying its investment
26amount commitments described in this subsection (b), then the

 

 

10200SB3866ham004- 38 -LRB102 24630 LNS 38917 a

1utility shall no longer be eligible to annually update the
2performance-based formula rate tariff pursuant to subsection
3(d) of this Section. In such event, the then current rates
4shall remain in effect until such time as new rates are set
5pursuant to Article IX of this Act, subject to retroactive
6adjustment, with interest, to reconcile rates charged with
7actual costs.
8    If the Commission finds that a participating utility is no
9longer eligible to update the performance-based formula rate
10tariff pursuant to subsection (d) of this Section, or the
11performance-based formula rate is otherwise terminated, then
12the participating utility's voluntary commitments and
13obligations under this subsection (b) shall immediately
14terminate, except for the utility's obligation to pay an
15amount already owed to the fund for training grants pursuant
16to a Commission order.
17    In meeting the obligations of this subsection (b), to the
18extent feasible and consistent with State and federal law, the
19investments under the infrastructure investment program should
20provide employment opportunities for all segments of the
21population and workforce, including minority-owned and
22female-owned business enterprises, and shall not, consistent
23with State and federal law, discriminate based on race or
24socioeconomic status.
25    (b-5) Nothing in this Section shall prohibit the
26Commission from investigating the prudence and reasonableness

 

 

10200SB3866ham004- 39 -LRB102 24630 LNS 38917 a

1of the expenditures made under the infrastructure investment
2program during the annual review required by subsection (d) of
3this Section and shall, as part of such investigation,
4determine whether the utility's actual costs under the program
5are prudent and reasonable. The fact that a participating
6utility invests more than the minimum amounts specified in
7subsection (b) of this Section or its plan shall not imply
8imprudence or unreasonableness.
9    If the participating utility finds that it is implementing
10its plan for satisfying the infrastructure investment program
11commitments described in subsection (b) of this Section at a
12cost below the estimated amounts specified in subsection (b)
13of this Section, then the utility may file a petition with the
14Commission requesting that it be permitted to satisfy its
15commitments by spending less than the estimated amounts
16specified in subsection (b) of this Section. The Commission
17shall, after notice and hearing, enter its order approving, or
18approving as modified, or denying each such petition within
19150 days after the filing of the petition.
20    In no event, absent General Assembly approval, shall the
21capital investment costs incurred by a participating utility
22other than a combination utility in satisfying its
23infrastructure investment program commitments described in
24subsection (b) of this Section exceed $3,000,000,000 or, for a
25participating utility that is a combination utility,
26$720,000,000. If the participating utility's updated cost

 

 

10200SB3866ham004- 40 -LRB102 24630 LNS 38917 a

1estimates for satisfying its infrastructure investment program
2commitments described in subsection (b) of this Section exceed
3the limitation imposed by this subsection (b-5), then it shall
4submit a report to the Commission that identifies the
5increased costs and explains the reason or reasons for the
6increased costs no later than the year in which the utility
7estimates it will exceed the limitation. The Commission shall
8review the report and shall, within 90 days after the
9participating utility files the report, report to the General
10Assembly its findings regarding the participating utility's
11report. If the General Assembly does not amend the limitation
12imposed by this subsection (b-5), then the utility may modify
13its plan so as not to exceed the limitation imposed by this
14subsection (b-5) and may propose corresponding changes to the
15metrics established pursuant to subparagraphs (5) through (8)
16of subsection (f) of this Section, and the Commission may
17modify the metrics and incremental savings goals established
18pursuant to subsection (f) of this Section accordingly.
19    (b-10) All participating utilities shall make
20contributions for an energy low-income and support program in
21accordance with this subsection. Beginning no later than 180
22days after a participating utility files a performance-based
23formula rate tariff pursuant to subsection (c) of this
24Section, or beginning no later than January 1, 2012 if such
25utility files such performance-based formula rate tariff
26within 14 days of December 30, 2011 (the effective date of

 

 

10200SB3866ham004- 41 -LRB102 24630 LNS 38917 a

1Public Act 97-646), and without obtaining any approvals from
2the Commission or any other agency other than as set forth in
3this Section, regardless of whether any such approval would
4otherwise be required, a participating utility other than a
5combination utility shall pay $10,000,000 per year for 5 years
6and a participating utility that is a combination utility
7shall pay $1,000,000 per year for 10 years to the energy
8low-income and support program, which is intended to fund
9customer assistance programs with the primary purpose being
10avoidance of imminent disconnection. Such programs may
11include:
12        (1) a residential hardship program that may partner
13    with community-based organizations, including senior
14    citizen organizations, and provides grants to low-income
15    residential customers, including low-income senior
16    citizens, who demonstrate a hardship;
17        (2) a program that provides grants and other bill
18    payment concessions to veterans with disabilities who
19    demonstrate a hardship and members of the armed services
20    or reserve forces of the United States or members of the
21    Illinois National Guard who are on active duty pursuant to
22    an executive order of the President of the United States,
23    an act of the Congress of the United States, or an order of
24    the Governor and who demonstrate a hardship;
25        (3) a budget assistance program that provides tools
26    and education to low-income senior citizens to assist them

 

 

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1    with obtaining information regarding energy usage and
2    effective means of managing energy costs;
3        (4) a non-residential special hardship program that
4    provides grants to non-residential customers such as small
5    businesses and non-profit organizations that demonstrate a
6    hardship, including those providing services to senior
7    citizen and low-income customers; and
8        (5) a performance-based assistance program that
9    provides grants to encourage residential customers to make
10    on-time payments by matching a portion of the customer's
11    payments or providing credits towards arrearages.
12    The payments made by a participating utility pursuant to
13this subsection (b-10) shall not be a recoverable expense. A
14participating utility may elect to fund either new or existing
15customer assistance programs, including, but not limited to,
16those that are administered by the utility.
17    Programs that use funds that are provided by a
18participating utility to reduce utility bills may be
19implemented through tariffs that are filed with and reviewed
20by the Commission. If a utility elects to file tariffs with the
21Commission to implement all or a portion of the programs,
22those tariffs shall, regardless of the date actually filed, be
23deemed accepted and approved, and shall become effective on
24December 30, 2011 (the effective date of Public Act 97-646).
25The participating utilities whose customers benefit from the
26funds that are disbursed as contemplated in this Section shall

 

 

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1file annual reports documenting the disbursement of those
2funds with the Commission. The Commission has the authority to
3audit disbursement of the funds to ensure they were disbursed
4consistently with this Section.
5    If the Commission finds that a participating utility is no
6longer eligible to update the performance-based formula rate
7tariff pursuant to subsection (d) of this Section, or the
8performance-based formula rate is otherwise terminated, then
9the participating utility's voluntary commitments and
10obligations under this subsection (b-10) shall immediately
11terminate.
12    (c) A participating utility may elect to recover its
13delivery services costs through a performance-based formula
14rate approved by the Commission, which shall specify the cost
15components that form the basis of the rate charged to
16customers with sufficient specificity to operate in a
17standardized manner and be updated annually with transparent
18information that reflects the utility's actual costs to be
19recovered during the applicable rate year, which is the period
20beginning with the first billing day of January and extending
21through the last billing day of the following December. In the
22event the utility recovers a portion of its costs through
23automatic adjustment clause tariffs on October 26, 2011 (the
24effective date of Public Act 97-616), the utility may elect to
25continue to recover these costs through such tariffs, but then
26these costs shall not be recovered through the

 

 

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1performance-based formula rate. In the event the participating
2utility, prior to December 30, 2011 (the effective date of
3Public Act 97-646), filed electric delivery services tariffs
4with the Commission pursuant to Section 9-201 of this Act that
5are related to the recovery of its electric delivery services
6costs that are still pending on December 30, 2011 (the
7effective date of Public Act 97-646), the participating
8utility shall, at the time it files its performance-based
9formula rate tariff with the Commission, also file a notice of
10withdrawal with the Commission to withdraw the electric
11delivery services tariffs previously filed pursuant to Section
129-201 of this Act. Upon receipt of such notice, the Commission
13shall dismiss with prejudice any docket that had been
14initiated to investigate the electric delivery services
15tariffs filed pursuant to Section 9-201 of this Act, and such
16tariffs and the record related thereto shall not be the
17subject of any further hearing, investigation, or proceeding
18of any kind related to rates for electric delivery services.
19    The performance-based formula rate shall be implemented
20through a tariff filed with the Commission consistent with the
21provisions of this subsection (c) that shall be applicable to
22all delivery services customers. The Commission shall initiate
23and conduct an investigation of the tariff in a manner
24consistent with the provisions of this subsection (c) and the
25provisions of Article IX of this Act to the extent they do not
26conflict with this subsection (c). Except in the case where

 

 

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1the Commission finds, after notice and hearing, that a
2participating utility is not satisfying its investment amount
3commitments under subsection (b) of this Section, the
4performance-based formula rate shall remain in effect at the
5discretion of the utility. The performance-based formula rate
6approved by the Commission shall do the following:
7        (1) Provide for the recovery of the utility's actual
8    costs of delivery services that are prudently incurred and
9    reasonable in amount consistent with Commission practice
10    and law. The sole fact that a cost differs from that
11    incurred in a prior calendar year or that an investment is
12    different from that made in a prior calendar year shall
13    not imply the imprudence or unreasonableness of that cost
14    or investment.
15        (2) Reflect the utility's actual year-end capital
16    structure for the applicable calendar year, excluding
17    goodwill, subject to a determination of prudence and
18    reasonableness consistent with Commission practice and
19    law. To enable the financing of the incremental capital
20    expenditures, including regulatory assets, for electric
21    utilities that serve less than 3,000,000 retail customers
22    but more than 500,000 retail customers in the State, a
23    participating electric utility's actual year-end capital
24    structure that includes a common equity ratio, excluding
25    goodwill, of up to and including 50% of the total capital
26    structure shall be deemed reasonable and used to set

 

 

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1    rates.
2        (3) Include a cost of equity, which shall be
3    calculated as the sum of the following:
4            (A) the average for the applicable calendar year
5        of the monthly average yields of 30-year U.S. Treasury
6        bonds published by the Board of Governors of the
7        Federal Reserve System in its weekly H.15 Statistical
8        Release or successor publication; and
9            (B) 580 basis points.
10        At such time as the Board of Governors of the Federal
11    Reserve System ceases to include the monthly average
12    yields of 30-year U.S. Treasury bonds in its weekly H.15
13    Statistical Release or successor publication, the monthly
14    average yields of the U.S. Treasury bonds then having the
15    longest duration published by the Board of Governors in
16    its weekly H.15 Statistical Release or successor
17    publication shall instead be used for purposes of this
18    paragraph (3).
19        (4) Permit and set forth protocols, subject to a
20    determination of prudence and reasonableness consistent
21    with Commission practice and law, for the following:
22            (A) recovery of incentive compensation expense
23        that is based on the achievement of operational
24        metrics, including metrics related to budget controls,
25        outage duration and frequency, safety, customer
26        service, efficiency and productivity, and

 

 

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1        environmental compliance. Incentive compensation
2        expense that is based on net income or an affiliate's
3        earnings per share shall not be recoverable under the
4        performance-based formula rate;
5            (B) recovery of pension and other post-employment
6        benefits expense, provided that such costs are
7        supported by an actuarial study;
8            (C) recovery of severance costs, provided that if
9        the amount is over $3,700,000 for a participating
10        utility that is a combination utility or $10,000,000
11        for a participating utility that serves more than 3
12        million retail customers, then the full amount shall
13        be amortized consistent with subparagraph (F) of this
14        paragraph (4);
15            (D) investment return at a rate equal to the
16        utility's weighted average cost of long-term debt, on
17        the pension assets as, and in the amount, reported in
18        Account 186 (or in such other Account or Accounts as
19        such asset may subsequently be recorded) of the
20        utility's most recently filed FERC Form 1, net of
21        deferred tax benefits;
22            (E) recovery of the expenses related to the
23        Commission proceeding under this subsection (c) to
24        approve this performance-based formula rate and
25        initial rates or to subsequent proceedings related to
26        the formula, provided that the recovery shall be

 

 

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1        amortized over a 3-year period; recovery of expenses
2        related to the annual Commission proceedings under
3        subsection (d) of this Section to review the inputs to
4        the performance-based formula rate shall be expensed
5        and recovered through the performance-based formula
6        rate;
7            (F) amortization over a 5-year period of the full
8        amount of each charge or credit that exceeds
9        $3,700,000 for a participating utility that is a
10        combination utility or $10,000,000 for a participating
11        utility that serves more than 3 million retail
12        customers in the applicable calendar year and that
13        relates to a workforce reduction program's severance
14        costs, changes in accounting rules, changes in law,
15        compliance with any Commission-initiated audit, or a
16        single storm or other similar expense, provided that
17        any unamortized balance shall be reflected in rate
18        base. For purposes of this subparagraph (F), changes
19        in law includes any enactment, repeal, or amendment in
20        a law, ordinance, rule, regulation, interpretation,
21        permit, license, consent, or order, including those
22        relating to taxes, accounting, or to environmental
23        matters, or in the interpretation or application
24        thereof by any governmental authority occurring after
25        October 26, 2011 (the effective date of Public Act
26        97-616);

 

 

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1            (G) recovery of existing regulatory assets over
2        the periods previously authorized by the Commission;
3            (H) historical weather normalized billing
4        determinants; and
5            (I) allocation methods for common costs.
6        (5) Provide that if the participating utility's earned
7    rate of return on common equity related to the provision
8    of delivery services for the prior rate year (calculated
9    using costs and capital structure approved by the
10    Commission as provided in subparagraph (2) of this
11    subsection (c), consistent with this Section, in
12    accordance with Commission rules and orders, including,
13    but not limited to, adjustments for goodwill, and after
14    any Commission-ordered disallowances and taxes) is more
15    than 50 basis points higher than the rate of return on
16    common equity calculated pursuant to paragraph (3) of this
17    subsection (c) (after adjusting for any penalties to the
18    rate of return on common equity applied pursuant to the
19    performance metrics provision of subsection (f) of this
20    Section), then the participating utility shall apply a
21    credit through the performance-based formula rate that
22    reflects an amount equal to the value of that portion of
23    the earned rate of return on common equity that is more
24    than 50 basis points higher than the rate of return on
25    common equity calculated pursuant to paragraph (3) of this
26    subsection (c) (after adjusting for any penalties to the

 

 

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1    rate of return on common equity applied pursuant to the
2    performance metrics provision of subsection (f) of this
3    Section) for the prior rate year, adjusted for taxes. If
4    the participating utility's earned rate of return on
5    common equity related to the provision of delivery
6    services for the prior rate year (calculated using costs
7    and capital structure approved by the Commission as
8    provided in subparagraph (2) of this subsection (c),
9    consistent with this Section, in accordance with
10    Commission rules and orders, including, but not limited
11    to, adjustments for goodwill, and after any
12    Commission-ordered disallowances and taxes) is more than
13    50 basis points less than the return on common equity
14    calculated pursuant to paragraph (3) of this subsection
15    (c) (after adjusting for any penalties to the rate of
16    return on common equity applied pursuant to the
17    performance metrics provision of subsection (f) of this
18    Section), then the participating utility shall apply a
19    charge through the performance-based formula rate that
20    reflects an amount equal to the value of that portion of
21    the earned rate of return on common equity that is more
22    than 50 basis points less than the rate of return on common
23    equity calculated pursuant to paragraph (3) of this
24    subsection (c) (after adjusting for any penalties to the
25    rate of return on common equity applied pursuant to the
26    performance metrics provision of subsection (f) of this

 

 

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1    Section) for the prior rate year, adjusted for taxes.
2        (6) Provide for an annual reconciliation, as described
3    in subsection (d) of this Section, with interest, of the
4    revenue requirement reflected in rates for each calendar
5    year, beginning with the calendar year in which the
6    utility files its performance-based formula rate tariff
7    pursuant to subsection (c) of this Section, with what the
8    revenue requirement would have been had the actual cost
9    information for the applicable calendar year been
10    available at the filing date.
11    The utility shall file, together with its tariff, final
12data based on its most recently filed FERC Form 1, plus
13projected plant additions and correspondingly updated
14depreciation reserve and expense for the calendar year in
15which the tariff and data are filed, that shall populate the
16performance-based formula rate and set the initial delivery
17services rates under the formula. For purposes of this
18Section, "FERC Form 1" means the Annual Report of Major
19Electric Utilities, Licensees and Others that electric
20utilities are required to file with the Federal Energy
21Regulatory Commission under the Federal Power Act, Sections 3,
224(a), 304 and 209, modified as necessary to be consistent with
2383 Ill. Admin. Code Part 415 as of May 1, 2011. Nothing in this
24Section is intended to allow costs that are not otherwise
25recoverable to be recoverable by virtue of inclusion in FERC
26Form 1.

 

 

10200SB3866ham004- 52 -LRB102 24630 LNS 38917 a

1    After the utility files its proposed performance-based
2formula rate structure and protocols and initial rates, the
3Commission shall initiate a docket to review the filing. The
4Commission shall enter an order approving, or approving as
5modified, the performance-based formula rate, including the
6initial rates, as just and reasonable within 270 days after
7the date on which the tariff was filed, or, if the tariff is
8filed within 14 days after October 26, 2011 (the effective
9date of Public Act 97-616), then by May 31, 2012. Such review
10shall be based on the same evidentiary standards, including,
11but not limited to, those concerning the prudence and
12reasonableness of the costs incurred by the utility, the
13Commission applies in a hearing to review a filing for a
14general increase in rates under Article IX of this Act. The
15initial rates shall take effect within 30 days after the
16Commission's order approving the performance-based formula
17rate tariff.
18    Until such time as the Commission approves a different
19rate design and cost allocation pursuant to subsection (e) of
20this Section, rate design and cost allocation across customer
21classes shall be consistent with the Commission's most recent
22order regarding the participating utility's request for a
23general increase in its delivery services rates.
24    Subsequent changes to the performance-based formula rate
25structure or protocols shall be made as set forth in Section
269-201 of this Act, but nothing in this subsection (c) is

 

 

10200SB3866ham004- 53 -LRB102 24630 LNS 38917 a

1intended to limit the Commission's authority under Article IX
2and other provisions of this Act to initiate an investigation
3of a participating utility's performance-based formula rate
4tariff, provided that any such changes shall be consistent
5with paragraphs (1) through (6) of this subsection (c). Any
6change ordered by the Commission shall be made at the same time
7new rates take effect following the Commission's next order
8pursuant to subsection (d) of this Section, provided that the
9new rates take effect no less than 30 days after the date on
10which the Commission issues an order adopting the change.
11    A participating utility that files a tariff pursuant to
12this subsection (c) must submit a one-time $200,000 filing fee
13at the time the Chief Clerk of the Commission accepts the
14filing, which shall be a recoverable expense.
15    In the event the performance-based formula rate is
16terminated, the then current rates shall remain in effect
17until such time as new rates are set pursuant to Article IX of
18this Act, subject to retroactive rate adjustment, with
19interest, to reconcile rates charged with actual costs. At
20such time that the performance-based formula rate is
21terminated, the participating utility's voluntary commitments
22and obligations under subsection (b) of this Section shall
23immediately terminate, except for the utility's obligation to
24pay an amount already owed to the fund for training grants
25pursuant to a Commission order issued under subsection (b) of
26this Section.

 

 

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1    (d) Subsequent to the Commission's issuance of an order
2approving the utility's performance-based formula rate
3structure and protocols, and initial rates under subsection
4(c) of this Section, the utility shall file, on or before May 1
5of each year, with the Chief Clerk of the Commission its
6updated cost inputs to the performance-based formula rate for
7the applicable rate year and the corresponding new charges.
8Each such filing shall conform to the following requirements
9and include the following information:
10        (1) The inputs to the performance-based formula rate
11    for the applicable rate year shall be based on final
12    historical data reflected in the utility's most recently
13    filed annual FERC Form 1 plus projected plant additions
14    and correspondingly updated depreciation reserve and
15    expense for the calendar year in which the inputs are
16    filed. The filing shall also include a reconciliation of
17    the revenue requirement that was in effect for the prior
18    rate year (as set by the cost inputs for the prior rate
19    year) with the actual revenue requirement for the prior
20    rate year (determined using a year-end rate base) that
21    uses amounts reflected in the applicable FERC Form 1 that
22    reports the actual costs for the prior rate year. Any
23    over-collection or under-collection indicated by such
24    reconciliation shall be reflected as a credit against, or
25    recovered as an additional charge to, respectively, with
26    interest calculated at a rate equal to the utility's

 

 

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1    weighted average cost of capital approved by the
2    Commission for the prior rate year, the charges for the
3    applicable rate year. Provided, however, that the first
4    such reconciliation shall be for the calendar year in
5    which the utility files its performance-based formula rate
6    tariff pursuant to subsection (c) of this Section and
7    shall reconcile (i) the revenue requirement or
8    requirements established by the rate order or orders in
9    effect from time to time during such calendar year
10    (weighted, as applicable) with (ii) the revenue
11    requirement determined using a year-end rate base for that
12    calendar year calculated pursuant to the performance-based
13    formula rate using (A) actual costs for that year as
14    reflected in the applicable FERC Form 1, and (B) for the
15    first such reconciliation only, the cost of equity, which
16    shall be calculated as the sum of 590 basis points plus the
17    average for the applicable calendar year of the monthly
18    average yields of 30-year U.S. Treasury bonds published by
19    the Board of Governors of the Federal Reserve System in
20    its weekly H.15 Statistical Release or successor
21    publication. The first such reconciliation is not intended
22    to provide for the recovery of costs previously excluded
23    from rates based on a prior Commission order finding of
24    imprudence or unreasonableness. Each reconciliation shall
25    be certified by the participating utility in the same
26    manner that FERC Form 1 is certified. The filing shall

 

 

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1    also include the charge or credit, if any, resulting from
2    the calculation required by paragraph (6) of subsection
3    (c) of this Section.
4        Notwithstanding anything that may be to the contrary,
5    the intent of the reconciliation is to ultimately
6    reconcile the revenue requirement reflected in rates for
7    each calendar year, beginning with the calendar year in
8    which the utility files its performance-based formula rate
9    tariff pursuant to subsection (c) of this Section, with
10    what the revenue requirement determined using a year-end
11    rate base for the applicable calendar year would have been
12    had the actual cost information for the applicable
13    calendar year been available at the filing date.
14        (2) The new charges shall take effect beginning on the
15    first billing day of the following January billing period
16    and remain in effect through the last billing day of the
17    next December billing period regardless of whether the
18    Commission enters upon a hearing pursuant to this
19    subsection (d).
20        (3) The filing shall include relevant and necessary
21    data and documentation for the applicable rate year that
22    is consistent with the Commission's rules applicable to a
23    filing for a general increase in rates or any rules
24    adopted by the Commission to implement this Section.
25    Normalization adjustments shall not be required.
26    Notwithstanding any other provision of this Section or Act

 

 

10200SB3866ham004- 57 -LRB102 24630 LNS 38917 a

1    or any rule or other requirement adopted by the
2    Commission, a participating utility that is a combination
3    utility with more than one rate zone shall not be required
4    to file a separate set of such data and documentation for
5    each rate zone and may combine such data and documentation
6    into a single set of schedules.
7    Within 45 days after the utility files its annual update
8of cost inputs to the performance-based formula rate, the
9Commission shall have the authority, either upon complaint or
10its own initiative, but with reasonable notice, to enter upon
11a hearing concerning the prudence and reasonableness of the
12costs incurred by the utility to be recovered during the
13applicable rate year that are reflected in the inputs to the
14performance-based formula rate derived from the utility's FERC
15Form 1. During the course of the hearing, each objection shall
16be stated with particularity and evidence provided in support
17thereof, after which the utility shall have the opportunity to
18rebut the evidence. Discovery shall be allowed consistent with
19the Commission's Rules of Practice, which Rules shall be
20enforced by the Commission or the assigned administrative law
21judge. The Commission shall apply the same evidentiary
22standards, including, but not limited to, those concerning the
23prudence and reasonableness of the costs incurred by the
24utility, in the hearing as it would apply in a hearing to
25review a filing for a general increase in rates under Article
26IX of this Act. The Commission shall not, however, have the

 

 

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1authority in a proceeding under this subsection (d) to
2consider or order any changes to the structure or protocols of
3the performance-based formula rate approved pursuant to
4subsection (c) of this Section. In a proceeding under this
5subsection (d), the Commission shall enter its order no later
6than the earlier of 240 days after the utility's filing of its
7annual update of cost inputs to the performance-based formula
8rate or December 31. The Commission's determinations of the
9prudence and reasonableness of the costs incurred for the
10applicable calendar year shall be final upon entry of the
11Commission's order and shall not be subject to reopening,
12reexamination, or collateral attack in any other Commission
13proceeding, case, docket, order, rule or regulation, provided,
14however, that nothing in this subsection (d) shall prohibit a
15party from petitioning the Commission to rehear or appeal to
16the courts the order pursuant to the provisions of this Act.
17    In the event the Commission does not, either upon
18complaint or its own initiative, enter upon a hearing within
1945 days after the utility files the annual update of cost
20inputs to its performance-based formula rate, then the costs
21incurred for the applicable calendar year shall be deemed
22prudent and reasonable, and the filed charges shall not be
23subject to reopening, reexamination, or collateral attack in
24any other proceeding, case, docket, order, rule, or
25regulation.
26    A participating utility's first filing of the updated cost

 

 

10200SB3866ham004- 59 -LRB102 24630 LNS 38917 a

1inputs, and any Commission investigation of such inputs
2pursuant to this subsection (d) shall proceed notwithstanding
3the fact that the Commission's investigation under subsection
4(c) of this Section is still pending and notwithstanding any
5other law, order, rule, or Commission practice to the
6contrary.
7    (e) Nothing in subsections (c) or (d) of this Section
8shall prohibit the Commission from investigating, or a
9participating utility from filing, revenue-neutral tariff
10changes related to rate design of a performance-based formula
11rate that has been placed into effect for the utility.
12Following approval of a participating utility's
13performance-based formula rate tariff pursuant to subsection
14(c) of this Section, the utility shall make a filing with the
15Commission within one year after the effective date of the
16performance-based formula rate tariff that proposes changes to
17the tariff to incorporate the findings of any final rate
18design orders of the Commission applicable to the
19participating utility and entered subsequent to the
20Commission's approval of the tariff. The Commission shall,
21after notice and hearing, enter its order approving, or
22approving with modification, the proposed changes to the
23performance-based formula rate tariff within 240 days after
24the utility's filing. Following such approval, the utility
25shall make a filing with the Commission during each subsequent
263-year period that either proposes revenue-neutral tariff

 

 

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1changes or re-files the existing tariffs without change, which
2shall present the Commission with an opportunity to suspend
3the tariffs and consider revenue-neutral tariff changes
4related to rate design.
5    (f) Within 30 days after the filing of a tariff pursuant to
6subsection (c) of this Section, each participating utility
7shall develop and file with the Commission multi-year metrics
8designed to achieve, ratably (i.e., in equal segments) over a
910-year period, improvement over baseline performance values
10as follows:
11        (1) Twenty percent improvement in the System Average
12    Interruption Frequency Index, using a baseline of the
13    average of the data from 2001 through 2010.
14        (2) Fifteen percent improvement in the system Customer
15    Average Interruption Duration Index, using a baseline of
16    the average of the data from 2001 through 2010.
17        (3) For a participating utility other than a
18    combination utility, 20% improvement in the System Average
19    Interruption Frequency Index for its Southern Region,
20    using a baseline of the average of the data from 2001
21    through 2010. For purposes of this paragraph (3), Southern
22    Region shall have the meaning set forth in the
23    participating utility's most recent report filed pursuant
24    to Section 16-125 of this Act.
25        (3.5) For a participating utility other than a
26    combination utility, 20% improvement in the System Average

 

 

10200SB3866ham004- 61 -LRB102 24630 LNS 38917 a

1    Interruption Frequency Index for its Northeastern Region,
2    using a baseline of the average of the data from 2001
3    through 2010. For purposes of this paragraph (3.5),
4    Northeastern Region shall have the meaning set forth in
5    the participating utility's most recent report filed
6    pursuant to Section 16-125 of this Act.
7        (4) Seventy-five percent improvement in the total
8    number of customers who exceed the service reliability
9    targets as set forth in subparagraphs (A) through (C) of
10    paragraph (4) of subsection (b) of 83 Ill. Admin. Code
11    Part 411.140 as of May 1, 2011, using 2010 as the baseline
12    year.
13        (5) Reduction in issuance of estimated electric bills:
14    90% improvement for a participating utility other than a
15    combination utility, and 56% improvement for a
16    participating utility that is a combination utility, using
17    a baseline of the average number of estimated bills for
18    the years 2008 through 2010.
19        (6) Consumption on inactive meters: 90% improvement
20    for a participating utility other than a combination
21    utility, and 56% improvement for a participating utility
22    that is a combination utility, using a baseline of the
23    average unbilled kilowatthours for the years 2009 and
24    2010.
25        (7) Unaccounted for energy: 50% improvement for a
26    participating utility other than a combination utility

 

 

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1    using a baseline of the non-technical line loss
2    unaccounted for energy kilowatthours for the year 2009.
3        (8) Uncollectible expense: reduce uncollectible
4    expense by at least $30,000,000 for a participating
5    utility other than a combination utility and by at least
6    $3,500,000 for a participating utility that is a
7    combination utility, using a baseline of the average
8    uncollectible expense for the years 2008 through 2010.
9        (9) Opportunities for minority-owned and female-owned
10    business enterprises: design a performance metric
11    regarding the creation of opportunities for minority-owned
12    and female-owned business enterprises consistent with
13    State and federal law using a base performance value of
14    the percentage of the participating utility's capital
15    expenditures that were paid to minority-owned and
16    female-owned business enterprises in 2010.
17    The definitions set forth in 83 Ill. Admin. Code Part
18411.20 as of May 1, 2011 shall be used for purposes of
19calculating performance under paragraphs (1) through (3.5) of
20this subsection (f), provided, however, that the participating
21utility may exclude up to 9 extreme weather event days from
22such calculation for each year, and provided further that the
23participating utility shall exclude 9 extreme weather event
24days when calculating each year of the baseline period to the
25extent that there are 9 such days in a given year of the
26baseline period. For purposes of this Section, an extreme

 

 

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1weather event day is a 24-hour calendar day (beginning at
212:00 a.m. and ending at 11:59 p.m.) during which any weather
3event (e.g., storm, tornado) caused interruptions for 10,000
4or more of the participating utility's customers for 3 hours
5or more. If there are more than 9 extreme weather event days in
6a year, then the utility may choose no more than 9 extreme
7weather event days to exclude, provided that the same extreme
8weather event days are excluded from each of the calculations
9performed under paragraphs (1) through (3.5) of this
10subsection (f).
11    The metrics shall include incremental performance goals
12for each year of the 10-year period, which shall be designed to
13demonstrate that the utility is on track to achieve the
14performance goal in each category at the end of the 10-year
15period. The utility shall elect when the 10-year period shall
16commence for the metrics set forth in subparagraphs (1)
17through (4) and (9) of this subsection (f), provided that it
18begins no later than 14 months following the date on which the
19utility begins investing pursuant to subsection (b) of this
20Section, and when the 10-year period shall commence for the
21metrics set forth in subparagraphs (5) through (8) of this
22subsection (f), provided that it begins no later than 14
23months following the date on which the Commission enters its
24order approving the utility's Advanced Metering Infrastructure
25Deployment Plan pursuant to subsection (c) of Section 16-108.6
26of this Act.

 

 

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1    The metrics and performance goals set forth in
2subparagraphs (5) through (8) of this subsection (f) are based
3on the assumptions that the participating utility may fully
4implement the technology described in subsection (b) of this
5Section, including utilizing the full functionality of such
6technology and that there is no requirement for personal
7on-site notification. If the utility is unable to meet the
8metrics and performance goals set forth in subparagraphs (5)
9through (8) of this subsection (f) for such reasons, and the
10Commission so finds after notice and hearing, then the utility
11shall be excused from compliance, but only to the limited
12extent achievement of the affected metrics and performance
13goals was hindered by the less than full implementation.
14    (f-5) The financial penalties applicable to the metrics
15described in subparagraphs (1) through (8) of subsection (f)
16of this Section, as applicable, shall be applied through an
17adjustment to the participating utility's return on equity of
18no more than a total of 30 basis points in each of the first 3
19years, of no more than a total of 34 basis points in each of
20the 3 years thereafter, and of no more than a total of 38 basis
21points in each of the 4 years thereafter, as follows:
22        (1) With respect to each of the incremental annual
23    performance goals established pursuant to paragraph (1) of
24    subsection (f) of this Section,
25            (A) for each year that a participating utility
26        other than a combination utility does not achieve the

 

 

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1        annual goal, the participating utility's return on
2        equity shall be reduced as follows: during years 1
3        through 3, by 5 basis points; during years 4 through 6,
4        by 6 basis points; and during years 7 through 10, by 7
5        basis points; and
6            (B) for each year that a participating utility
7        that is a combination utility does not achieve the
8        annual goal, the participating utility's return on
9        equity shall be reduced as follows: during years 1
10        through 3, by 10 basis points; during years 4 through
11        6, by 12 basis points; and during years 7 through 10,
12        by 14 basis points.
13        (2) With respect to each of the incremental annual
14    performance goals established pursuant to paragraph (2) of
15    subsection (f) of this Section, for each year that the
16    participating utility does not achieve each such goal, the
17    participating utility's return on equity shall be reduced
18    as follows: during years 1 through 3, by 5 basis points;
19    during years 4 through 6, by 6 basis points; and during
20    years 7 through 10, by 7 basis points.
21        (3) With respect to each of the incremental annual
22    performance goals established pursuant to paragraphs (3)
23    and (3.5) of subsection (f) of this Section, for each year
24    that a participating utility other than a combination
25    utility does not achieve both such goals, the
26    participating utility's return on equity shall be reduced

 

 

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1    as follows: during years 1 through 3, by 5 basis points;
2    during years 4 through 6, by 6 basis points; and during
3    years 7 through 10, by 7 basis points.
4        (4) With respect to each of the incremental annual
5    performance goals established pursuant to paragraph (4) of
6    subsection (f) of this Section, for each year that the
7    participating utility does not achieve each such goal, the
8    participating utility's return on equity shall be reduced
9    as follows: during years 1 through 3, by 5 basis points;
10    during years 4 through 6, by 6 basis points; and during
11    years 7 through 10, by 7 basis points.
12        (5) With respect to each of the incremental annual
13    performance goals established pursuant to subparagraph (5)
14    of subsection (f) of this Section, for each year that the
15    participating utility does not achieve at least 95% of
16    each such goal, the participating utility's return on
17    equity shall be reduced by 5 basis points for each such
18    unachieved goal.
19        (6) With respect to each of the incremental annual
20    performance goals established pursuant to paragraphs (6),
21    (7), and (8) of subsection (f) of this Section, as
22    applicable, which together measure non-operational
23    customer savings and benefits relating to the
24    implementation of the Advanced Metering Infrastructure
25    Deployment Plan, as defined in Section 16-108.6 of this
26    Act, the performance under each such goal shall be

 

 

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1    calculated in terms of the percentage of the goal
2    achieved. The percentage of goal achieved for each of the
3    goals shall be aggregated, and an average percentage value
4    calculated, for each year of the 10-year period. If the
5    utility does not achieve an average percentage value in a
6    given year of at least 95%, the participating utility's
7    return on equity shall be reduced by 5 basis points.
8    The financial penalties shall be applied as described in
9this subsection (f-5) for the 12-month period in which the
10deficiency occurred through a separate tariff mechanism, which
11shall be filed by the utility together with its metrics. In the
12event the formula rate tariff established pursuant to
13subsection (c) of this Section terminates, the utility's
14obligations under subsection (f) of this Section and this
15subsection (f-5) shall also terminate, provided, however, that
16the tariff mechanism established pursuant to subsection (f) of
17this Section and this subsection (f-5) shall remain in effect
18until any penalties due and owing at the time of such
19termination are applied.
20    The Commission shall, after notice and hearing, enter an
21order within 120 days after the metrics are filed approving,
22or approving with modification, a participating utility's
23tariff or mechanism to satisfy the metrics set forth in
24subsection (f) of this Section. On June 1 of each subsequent
25year, each participating utility shall file a report with the
26Commission that includes, among other things, a description of

 

 

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1how the participating utility performed under each metric and
2an identification of any extraordinary events that adversely
3impacted the utility's performance. Whenever a participating
4utility does not satisfy the metrics required pursuant to
5subsection (f) of this Section, the Commission shall, after
6notice and hearing, enter an order approving financial
7penalties in accordance with this subsection (f-5). The
8Commission-approved financial penalties shall be applied
9beginning with the next rate year. Nothing in this Section
10shall authorize the Commission to reduce or otherwise obviate
11the imposition of financial penalties for failing to achieve
12one or more of the metrics established pursuant to
13subparagraph (1) through (4) of subsection (f) of this
14Section.
15    (g) On or before July 31, 2014, each participating utility
16shall file a report with the Commission that sets forth the
17average annual increase in the average amount paid per
18kilowatthour for residential eligible retail customers,
19exclusive of the effects of energy efficiency programs,
20comparing the 12-month period ending May 31, 2012; the
2112-month period ending May 31, 2013; and the 12-month period
22ending May 31, 2014. For a participating utility that is a
23combination utility with more than one rate zone, the weighted
24average aggregate increase shall be provided. The report shall
25be filed together with a statement from an independent auditor
26attesting to the accuracy of the report. The cost of the

 

 

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1independent auditor shall be borne by the participating
2utility and shall not be a recoverable expense. "The average
3amount paid per kilowatthour" shall be based on the
4participating utility's tariffed rates actually in effect and
5shall not be calculated using any hypothetical rate or
6adjustments to actual charges (other than as specified for
7energy efficiency) as an input.
8    In the event that the average annual increase exceeds 2.5%
9as calculated pursuant to this subsection (g), then Sections
1016-108.5, 16-108.6, 16-108.7, and 16-108.8 of this Act, other
11than this subsection, shall be inoperative as they relate to
12the utility and its service area as of the date of the report
13due to be submitted pursuant to this subsection and the
14utility shall no longer be eligible to annually update the
15performance-based formula rate tariff pursuant to subsection
16(d) of this Section. In such event, the then current rates
17shall remain in effect until such time as new rates are set
18pursuant to Article IX of this Act, subject to retroactive
19adjustment, with interest, to reconcile rates charged with
20actual costs, and the participating utility's voluntary
21commitments and obligations under subsection (b) of this
22Section shall immediately terminate, except for the utility's
23obligation to pay an amount already owed to the fund for
24training grants pursuant to a Commission order issued under
25subsection (b) of this Section.
26    In the event that the average annual increase is 2.5% or

 

 

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1less as calculated pursuant to this subsection (g), then the
2performance-based formula rate shall remain in effect as set
3forth in this Section.
4    For purposes of this Section, the amount per kilowatthour
5means the total amount paid for electric service expressed on
6a per kilowatthour basis, and the total amount paid for
7electric service includes without limitation amounts paid for
8supply, transmission, distribution, surcharges, and add-on
9taxes exclusive of any increases in taxes or new taxes imposed
10after October 26, 2011 (the effective date of Public Act
1197-616). For purposes of this Section, "eligible retail
12customers" shall have the meaning set forth in Section
1316-111.5 of this Act.
14    The fact that this Section becomes inoperative as set
15forth in this subsection shall not be construed to mean that
16the Commission may reexamine or otherwise reopen prudence or
17reasonableness determinations already made.
18    (h) By December 31, 2017, the Commission shall prepare and
19file with the General Assembly a report on the infrastructure
20program and the performance-based formula rate. The report
21shall include the change in the average amount per
22kilowatthour paid by residential customers between June 1,
232011 and May 31, 2017. If the change in the total average rate
24paid exceeds 2.5% compounded annually, the Commission shall
25include in the report an analysis that shows the portion of the
26change due to the delivery services component and the portion

 

 

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1of the change due to the supply component of the rate. The
2report shall include separate sections for each participating
3utility.
4    Sections 16-108.5, 16-108.6, 16-108.7, and 16-108.8 of
5this Act, other than this subsection (h) and subsection (i) of
6this Section, are inoperative after December 31, 2022 for
7every participating utility, after which time a participating
8utility shall no longer be eligible to annually update the
9performance-based formula rate tariff pursuant to subsection
10(d) of this Section. At such time, the then current rates shall
11remain in effect until such time as new rates are set pursuant
12to Article IX of this Act, subject to retroactive adjustment,
13with interest, to reconcile rates charged with actual costs.
14    The fact that this Section becomes inoperative as set
15forth in this subsection shall not be construed to mean that
16the Commission may reexamine or otherwise reopen prudence or
17reasonableness determinations already made.
18    (i) While a participating utility may use, develop, and
19maintain broadband systems and the delivery of broadband
20services, voice-over-internet-protocol services,
21telecommunications services, and cable and video programming
22services for use in providing delivery services and Smart Grid
23functionality or application to its retail customers,
24including, but not limited to, the installation,
25implementation and maintenance of Smart Grid electric system
26upgrades as defined in Section 16-108.6 of this Act, a

 

 

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1participating utility is prohibited from providing offering to
2its retail customers broadband services or the delivery of
3broadband services, voice-over-internet-protocol services,
4telecommunications services, or cable or video programming
5services, unless they are part of a service directly related
6to delivery services or Smart Grid functionality or
7applications as defined in Section 16-108.6 of this Act, and
8from recovering the costs of such offerings from retail
9customers. The prohibition set forth in this subsection (i) is
10inoperative after December 31, 2027 for every participating
11utility.
12    (j) Nothing in this Section is intended to legislatively
13overturn the opinion issued in Commonwealth Edison Co. v. Ill.
14Commerce Comm'n, Nos. 2-08-0959, 2-08-1037, 2-08-1137,
151-08-3008, 1-08-3030, 1-08-3054, 1-08-3313 cons. (Ill. App.
16Ct. 2d Dist. Sept. 30, 2010). Public Act 97-616 shall not be
17construed as creating a contract between the General Assembly
18and the participating utility, and shall not establish a
19property right in the participating utility.
20    (k) The changes made in subsections (c) and (d) of this
21Section by Public Act 98-15 are intended to be a restatement
22and clarification of existing law, and intended to give
23binding effect to the provisions of House Resolution 1157
24adopted by the House of Representatives of the 97th General
25Assembly and Senate Resolution 821 adopted by the Senate of
26the 97th General Assembly that are reflected in paragraph (3)

 

 

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1of this subsection. In addition, Public Act 98-15 preempts and
2supersedes any final Commission orders entered in Docket Nos.
311-0721, 12-0001, 12-0293, and 12-0321 to the extent
4inconsistent with the amendatory language added to subsections
5(c) and (d).
6        (1) No earlier than 5 business days after May 22, 2013
7    (the effective date of Public Act 98-15), each
8    participating utility shall file any tariff changes
9    necessary to implement the amendatory language set forth
10    in subsections (c) and (d) of this Section by Public Act
11    98-15 and a revised revenue requirement under the
12    participating utility's performance-based formula rate.
13    The Commission shall enter a final order approving such
14    tariff changes and revised revenue requirement within 21
15    days after the participating utility's filing.
16        (2) Notwithstanding anything that may be to the
17    contrary, a participating utility may file a tariff to
18    retroactively recover its previously unrecovered actual
19    costs of delivery service that are no longer subject to
20    recovery through a reconciliation adjustment under
21    subsection (d) of this Section. This retroactive recovery
22    shall include any derivative adjustments resulting from
23    the changes to subsections (c) and (d) of this Section by
24    Public Act 98-15. Such tariff shall allow the utility to
25    assess, on current customer bills over a period of 12
26    monthly billing periods, a charge or credit related to

 

 

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1    those unrecovered costs with interest at the utility's
2    weighted average cost of capital during the period in
3    which those costs were unrecovered. A participating
4    utility may file a tariff that implements a retroactive
5    charge or credit as described in this paragraph for
6    amounts not otherwise included in the tariff filing
7    provided for in paragraph (1) of this subsection (k). The
8    Commission shall enter a final order approving such tariff
9    within 21 days after the participating utility's filing.
10        (3) The tariff changes described in paragraphs (1) and
11    (2) of this subsection (k) shall relate only to, and be
12    consistent with, the following provisions of Public Act
13    98-15: paragraph (2) of subsection (c) regarding year-end
14    capital structure, subparagraph (D) of paragraph (4) of
15    subsection (c) regarding pension assets, and subsection
16    (d) regarding the reconciliation components related to
17    year-end rate base and interest calculated at a rate equal
18    to the utility's weighted average cost of capital.
19        (4) Nothing in this subsection is intended to effect a
20    dismissal of or otherwise affect an appeal from any final
21    Commission orders entered in Docket Nos. 11-0721, 12-0001,
22    12-0293, and 12-0321 other than to the extent of the
23    amendatory language contained in subsections (c) and (d)
24    of this Section of Public Act 98-15.
25    (l) Each participating utility shall be deemed to have
26been in full compliance with all requirements of subsection

 

 

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1(b) of this Section, subsection (c) of this Section, Section
216-108.6 of this Act, and all Commission orders entered
3pursuant to Sections 16-108.5 and 16-108.6 of this Act, up to
4and including May 22, 2013 (the effective date of Public Act
598-15). The Commission shall not undertake any investigation
6of such compliance and no penalty shall be assessed or adverse
7action taken against a participating utility for noncompliance
8with Commission orders associated with subsection (b) of this
9Section, subsection (c) of this Section, and Section 16-108.6
10of this Act prior to such date. Each participating utility
11other than a combination utility shall be permitted, without
12penalty, a period of 12 months after such effective date to
13take actions required to ensure its infrastructure investment
14program is in compliance with subsection (b) of this Section
15and with Section 16-108.6 of this Act. Provided further, the
16following subparagraphs shall apply to a participating utility
17other than a combination utility:
18        (A) if the Commission has initiated a proceeding
19    pursuant to subsection (e) of Section 16-108.6 of this Act
20    that is pending as of May 22, 2013 (the effective date of
21    Public Act 98-15), then the order entered in such
22    proceeding shall, after notice and hearing, accelerate the
23    commencement of the meter deployment schedule approved in
24    the final Commission order on rehearing entered in Docket
25    No. 12-0298;
26        (B) if the Commission has entered an order pursuant to

 

 

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1    subsection (e) of Section 16-108.6 of this Act prior to
2    May 22, 2013 (the effective date of Public Act 98-15) that
3    does not accelerate the commencement of the meter
4    deployment schedule approved in the final Commission order
5    on rehearing entered in Docket No. 12-0298, then the
6    utility shall file with the Commission, within 45 days
7    after such effective date, a plan for accelerating the
8    commencement of the utility's meter deployment schedule
9    approved in the final Commission order on rehearing
10    entered in Docket No. 12-0298; the Commission shall reopen
11    the proceeding in which it entered its order pursuant to
12    subsection (e) of Section 16-108.6 of this Act and shall,
13    after notice and hearing, enter an amendatory order that
14    approves or approves as modified such accelerated plan
15    within 90 days after the utility's filing; or
16        (C) if the Commission has not initiated a proceeding
17    pursuant to subsection (e) of Section 16-108.6 of this Act
18    prior to May 22, 2013 (the effective date of Public Act
19    98-15), then the utility shall file with the Commission,
20    within 45 days after such effective date, a plan for
21    accelerating the commencement of the utility's meter
22    deployment schedule approved in the final Commission order
23    on rehearing entered in Docket No. 12-0298 and the
24    Commission shall, after notice and hearing, approve or
25    approve as modified such plan within 90 days after the
26    utility's filing.

 

 

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1    Any schedule for meter deployment approved by the
2Commission pursuant to this subsection (l) shall take into
3consideration procurement times for meters and other equipment
4and operational issues. Nothing in Public Act 98-15 shall
5shorten or extend the end dates for the 5-year or 10-year
6periods set forth in subsection (b) of this Section or Section
716-108.6 of this Act. Nothing in this subsection is intended
8to address whether a participating utility has, or has not,
9satisfied any or all of the metrics and performance goals
10established pursuant to subsection (f) of this Section.
11    (m) The provisions of Public Act 98-15 are severable under
12Section 1.31 of the Statute on Statutes.
13(Source: P.A. 99-143, eff. 7-27-15; 99-642, eff. 7-28-16;
1499-906, eff. 6-1-17; 100-840, eff. 8-13-18.)
 
15    (220 ILCS 5/16-108.30)
16    Sec. 16-108.30. Energy Transition Assistance Fund.
17    (a) The Energy Transition Assistance Fund is hereby
18created as a special fund in the State Treasury. The Energy
19Transition Assistance Fund is authorized to receive moneys
20collected pursuant to this Section. Subject to appropriation,
21the Department of Commerce and Economic Opportunity shall use
22moneys from the Energy Transition Assistance Fund consistent
23with the purposes of this Act.
24    (b) An electric utility serving more than 500,000
25customers in the State shall assess an energy transition

 

 

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1assistance charge on all its retail customers for the Energy
2Transition Assistance Fund. The utility's total charge shall
3be set based upon the value determined by the Department of
4Commerce and Economic Opportunity pursuant to subsection (d)
5or (e), as applicable, of Section 605-1075 of the Department
6of Commerce and Economic Opportunity Law of the Civil
7Administrative Code of Illinois. For each utility, the charge
8shall be recovered through a single, uniform cents per
9kilowatt-hour charge applicable to all retail customers. For
10each utility, the charge shall not exceed 1.3% of the amount
11paid per kilowatthour by eligible retail those customers
12during the year ending May 31, 2009.
13    (c) Within 75 days of the effective date of this
14amendatory Act of the 102nd General Assembly, each electric
15utility serving more than 500,000 customers in the State shall
16file with the Illinois Commerce Commission tariffs
17incorporating the energy transition assistance charge in other
18charges stated in such tariffs, which energy transition
19assistance charges shall become effective no later than the
20beginning of the first billing cycle that begins on or after
21January 1, 2022. Each electric utility serving more than
22500,000 customers in the State shall, prior to the beginning
23of each calendar year starting with calendar year 2023, file
24with the Illinois Commerce Commission tariff revisions to
25incorporate annual revisions to the energy transition
26assistance charge as prescribed by the Department of Commerce

 

 

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1and Economic Opportunity pursuant to Section 605-1075 of the
2Department of Commerce and Economic Opportunity Law of the
3Civil Administrative Code of Illinois so that such revision
4becomes effective no later than the beginning of the first
5billing cycle in each respective year.
6    (d) The energy transition assistance charge shall be
7considered a charge for public utility service.
8    (e) By the 20th day of the month following the month in
9which the charges imposed by this Section were collected, each
10electric utility serving more than 500,000 customers in the
11State shall remit to Department of Revenue all moneys received
12as payment of the energy transition assistance charge on a
13return prescribed and furnished by the Department of Revenue
14showing such information as the Department of Revenue may
15reasonably require. If a customer makes a partial payment, a
16public utility may apply such partial payments first to
17amounts owed to the utility. No customer may be subjected to
18disconnection of his or her utility service for failure to pay
19the energy transition assistance charge.
20    If any payment provided for in this subsection exceeds the
21electric utility's liabilities under this Act, as shown on an
22original return, the Department may authorize the electric
23utility to credit such excess payment against liability
24subsequently to be remitted to the Department under this Act,
25in accordance with reasonable rules adopted by the Department.
26    All the provisions of Sections 4, 5, 5a, 5b, 5c, 5d, 5e,

 

 

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15f, 5g, 5i, 5j, 6, 6a, 6b, 6c, 7, 8, 9, 10, 11, 11a, 12, and 13
2of the Retailers' Occupation Tax Act that are not inconsistent
3with this Act apply, as far as practicable, to the charge
4imposed by this Act to the same extent as if those provisions
5were included in this Act. References in the incorporated
6Sections of the Retailers' Occupation Tax Act to retailers, to
7sellers, or to persons engaged in the business of selling
8tangible personal property mean persons required to remit the
9charge imposed under this Act.
10    (f) The Department of Revenue shall deposit into the
11Energy Transition Assistance Fund all moneys remitted to it in
12accordance with this Section.
13    (g) The Department of Revenue may establish such rules as
14it deems necessary to implement this Section.
15    (h) The Department of Commerce and Economic Opportunity
16may establish such rules as it deems necessary to implement
17this Section.
18(Source: P.A. 102-662, eff. 9-15-21.)
 
19    (220 ILCS 5/16-111.11 new)
20    Sec. 16-111.11. Supplier diversity reporting for
21non-utilities.
22    (a) The following entities shall submit an annual supplier
23diversity report to the Commission for a given year:
24        (1) entities that received a contract to provide more
25    than 10,000 renewable energy credits approved by the

 

 

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1    Commission in a given year pursuant to subparagraph (iii)
2    of paragraph (5) of subsection (b) of Section 16-111.5;
3        (2) entities that received a contract to provide more
4    than 10,000 renewable energy credits approved by the
5    Commission in a given year pursuant to subsection (e) of
6    Section 16-111.5;
7        (3) alternative retail electric suppliers that have
8    yearly sales in the State of 1,000,000,000 kilowatt hours
9    or more, and alternative gas suppliers as defined in
10    Section 19-105 that have yearly sales in the State of
11    1,000,000 dekatherms or more;
12        (4) entities constructing or operating an HVDC
13    transmission line as defined in Section 1-10 of the
14    Illinois Power Agency Act or entities constructing or
15    operating transmission facilities under a certificate of
16    public convenience and necessity issued pursuant to
17    subsection (b-5) of Section 8-406;
18        (5) entities installing more than 100 energy
19    efficiency measures with a certificate approved by the
20    Commission pursuant to Section 16-128B; and
21        (6) other suppliers of electricity generated from any
22    resource, including, but not limited to, hydro, nuclear,
23    coal, natural gas, and any other supplier of energy within
24    this State.
25    (b) An annual report filed pursuant to this Section shall
26be filed on an electronic form as designed by the Commission by

 

 

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1June 1, 2023 and every June 1 thereafter, in a searchable Adobe
2PDF format, on all procurement goals and actual spending for
3women-owned businesses, minority-owned businesses,
4veteran-owned businesses, and small business enterprises in
5the previous calendar year related to the performance of
6obligations in the State of the contracts of licenses listed
7in subsection (a). These goals shall be expressed as a
8percentage of the total work performed by the entity
9submitting the report. The actual spending for all women-owned
10businesses, minority-owned businesses, veteran-owned
11businesses, and small business enterprises shall also be
12expressed as a percentage of the total work performed by the
13entity submitting the report. Notwithstanding any provision of
14law to the contrary, any entity with obligations related to
15equity eligible actions pursuant to the Illinois Power Agency
16Act may express such goals and spending in those terms.
17    Each participating entity in its annual report shall
18include the following information related to the entity's
19operations in the State related to the certificates or
20activities listed in subsection (a):
21        (1) an explanation of the plan for the next year to
22    increase participation;
23        (2) an explanation of the plan to increase the goals;
24        (3) the areas of procurement each entity shall be
25    actively seeking more participation in the next year;
26        (4) an outline of the plan to alert and encourage

 

 

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1    potential vendors in that area to seek business from the
2    entity;
3        (5) an explanation of the challenges faced in finding
4    quality vendors and offer any suggestions for what the
5    Commission could do to be helpful to identify those
6    vendors;
7        (6) a list of the certifications the entity
8    recognizes;
9        (7) the point of contact for any potential vendor who
10    wants to do business with the entity and explain the
11    process for a vendor to enroll with the company as a
12    minority-owned, women-owned, or veteran-owned company; and
13        (8) any particular success stories to encourage other
14    entities to emulate best practices.
15    (c) Each annual report shall include as much
16State-specific data as possible. If the submitting entity does
17not submit State-specific data, then the entity shall include
18any national data it does have and explain why it could not
19submit State-specific data and how it intends to do so in
20future reports.
21    (d) Each annual report shall include the rules,
22regulations, and definitions used for the procurement goals in
23the entity's annual report.
24    (e) Each annual report filed or submitted under this
25Section shall be submitted with the Commission. The Commission
26shall not be required or authorized to compel production of

 

 

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1any report under this Section. The Commission shall hold an
2annual workshop open to the public in 2024 and every year
3thereafter on the state of supplier diversity to
4collaboratively seek solutions to structural impediments to
5achieving stated goals, including testimony from participating
6entities as well as subject matter experts and advocates in a
7non-antagonistic manner. The Commission shall invite all
8entities submitting a report pursuant to this Section. The
9Commission shall publish a database on its website of the
10point of contact for each participating entity for supplier
11diversity, along with a list of certifications each company
12recognizes from the information submitted in each annual
13report. The Commission shall publish each annual report on its
14website and shall maintain each annual report for at least 5
15years.
 
16    Section 1-15. The Environmental Protection Act is amended
17by changing Section 9.15 as follows:
 
18    (415 ILCS 5/9.15)
19    Sec. 9.15. Greenhouse gases.
20    (a) An air pollution construction permit shall not be
21required due to emissions of greenhouse gases if the
22equipment, site, or source is not subject to regulation, as
23defined by 40 CFR 52.21, as now or hereafter amended, for
24greenhouse gases or is otherwise not addressed in this Section

 

 

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1or by the Board in regulations for greenhouse gases. These
2exemptions do not relieve an owner or operator from the
3obligation to comply with other applicable rules or
4regulations.
5    (b) An air pollution operating permit shall not be
6required due to emissions of greenhouse gases if the
7equipment, site, or source is not subject to regulation, as
8defined by Section 39.5 of this Act, for greenhouse gases or is
9otherwise not addressed in this Section or by the Board in
10regulations for greenhouse gases. These exemptions do not
11relieve an owner or operator from the obligation to comply
12with other applicable rules or regulations.
13    (c) (Blank).
14    (d) (Blank).
15    (e) (Blank).
16    (f) As used in this Section:
17    "Carbon dioxide emission" means the plant annual CO2 total
18output emission as measured by the United States Environmental
19Protection Agency in its Emissions & Generation Resource
20Integrated Database (eGrid), or its successor.
21    "Carbon dioxide equivalent emissions" or "CO2e" means the
22sum total of the mass amount of emissions in tons per year,
23calculated by multiplying the mass amount of each of the 6
24greenhouse gases specified in Section 3.207, in tons per year,
25by its associated global warming potential as set forth in 40
26CFR 98, subpart A, table A-1 or its successor, and then adding

 

 

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1them all together.
2    "Cogeneration" or "combined heat and power" refers to any
3system that, either simultaneously or sequentially, produces
4electricity and useful thermal energy from a single fuel
5source.
6    "Copollutants" refers to the 6 criteria pollutants that
7have been identified by the United States Environmental
8Protection Agency pursuant to the Clean Air Act.
9    "Electric generating unit" or "EGU" means a fossil
10fuel-fired stationary boiler, combustion turbine, or combined
11cycle system that serves a generator that has a nameplate
12capacity greater than 25 MWe and produces electricity for
13sale.
14    "Environmental justice community" means the definition of
15that term based on existing methodologies and findings, used
16and as may be updated by the Illinois Power Agency and its
17program administrator in the Illinois Solar for All Program.
18    "Equity investment eligible community" or "eligible
19community" means the geographic areas throughout Illinois that
20would most benefit from equitable investments by the State
21designed to combat discrimination and foster sustainable
22economic growth. Specifically, eligible community means the
23following areas:
24        (1) areas where residents have been historically
25    excluded from economic opportunities, including
26    opportunities in the energy sector, as defined as R3 areas

 

 

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1    pursuant to Section 10-40 of the Cannabis Regulation and
2    Tax Act; and
3        (2) areas where residents have been historically
4    subject to disproportionate burdens of pollution,
5    including pollution from the energy sector, as established
6    by environmental justice communities as defined by the
7    Illinois Power Agency pursuant to the Illinois Power
8    Agency Act, excluding any racial or ethnic indicators.
9    "Equity investment eligible person" or "eligible person"
10means the persons who would most benefit from equitable
11investments by the State designed to combat discrimination and
12foster sustainable economic growth. Specifically, eligible
13person means the following people:
14        (1) persons whose primary residence is in an equity
15    investment eligible community;
16        (2) persons whose primary residence is in a
17    municipality, or a county with a population under 100,000,
18    where the closure of an electric generating unit or mine
19    has been publicly announced or the electric generating
20    unit or mine is in the process of closing or closed within
21    the last 5 years;
22        (3) persons who are graduates of or currently enrolled
23    in the foster care system; or
24        (4) persons who were formerly incarcerated.
25    "Existing emissions" means:
26        (1) for CO2e, the total average tons-per-year of CO2e

 

 

10200SB3866ham004- 88 -LRB102 24630 LNS 38917 a

1    emitted by the EGU or large GHG-emitting unit either in
2    the years 2018 through 2020 or, if the unit was not yet in
3    operation by January 1, 2018, in the first 3 full years of
4    that unit's operation; and
5        (2) for any copollutant, the total average
6    tons-per-year of that copollutant emitted by the EGU or
7    large GHG-emitting unit either in the years 2018 through
8    2020 or, if the unit was not yet in operation by January 1,
9    2018, in the first 3 full years of that unit's operation.
10    "Green hydrogen" means a power plant technology in which
11an EGU creates electric power exclusively from electrolytic
12hydrogen, in a manner that produces zero carbon and
13copollutant emissions, using hydrogen fuel that is
14electrolyzed using a 100% renewable zero carbon emission
15energy source.
16    "Large greenhouse gas-emitting unit" or "large
17GHG-emitting unit" means a unit that is an electric generating
18unit or other fossil fuel-fired unit that itself has a
19nameplate capacity or serves a generator that has a nameplate
20capacity greater than 25 MWe and that produces electricity,
21including, but not limited to, coal-fired, coal-derived,
22oil-fired, natural gas-fired, and cogeneration units.
23    "NOx emission rate" means the plant annual NOx total output
24emission rate as measured by the United States Environmental
25Protection Agency in its Emissions & Generation Resource
26Integrated Database (eGrid), or its successor, in the most

 

 

10200SB3866ham004- 89 -LRB102 24630 LNS 38917 a

1recent year for which data is available.
2    "Public greenhouse gas-emitting units" or "public
3GHG-emitting unit" means large greenhouse gas-emitting units,
4including EGUs, that are wholly owned, directly or indirectly,
5by one or more municipalities, municipal corporations, joint
6municipal electric power agencies, electric cooperatives, or
7other governmental or nonprofit entities, whether organized
8and created under the laws of Illinois or another state.
9    "SO2 emission rate" means the "plant annual SO2 total
10output emission rate" as measured by the United States
11Environmental Protection Agency in its Emissions & Generation
12Resource Integrated Database (eGrid), or its successor, in the
13most recent year for which data is available.
14    (g) All EGUs and large greenhouse gas-emitting units that
15use coal or oil as a fuel and are not public GHG-emitting units
16shall permanently reduce all CO2e and copollutant emissions to
17zero no later than January 1, 2030.
18    (h) All EGUs and large greenhouse gas-emitting units that
19use coal as a fuel and are public GHG-emitting units shall
20permanently reduce CO2e emissions to zero no later than
21December 31, 2045. Any source or plant with such units must
22also reduce their CO2e emissions by 45% from existing
23emissions by no later than January 1, 2035. If the emissions
24reduction requirement is not achieved by December 31, 2035,
25the plant shall retire one or more units or otherwise reduce
26its CO2e emissions by 45% from existing emissions by June 30,

 

 

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12038.
2    (i) All EGUs and large greenhouse gas-emitting units that
3use gas as a fuel and are not public GHG-emitting units shall
4permanently reduce all CO2e and copollutant emissions to zero,
5including through unit retirement or the use of 100% green
6hydrogen or other similar technology that is commercially
7proven to achieve zero carbon emissions, according to the
8following:
9        (1) No later than January 1, 2030: all EGUs and large
10    greenhouse gas-emitting units that have a NOx emissions
11    rate of greater than 0.12 lbs/MWh or a SO2 emission rate of
12    greater than 0.006 lb/MWh, and are located in or within 3
13    miles of an environmental justice community designated as
14    of January 1, 2021 or an equity investment eligible
15    community.
16        (2) No later than January 1, 2040: all EGUs and large
17    greenhouse gas-emitting units that have a NOx emission
18    rate of greater than 0.12 lbs/MWh or a SO2 emission rate
19    greater than 0.006 lb/MWh, and are not located in or
20    within 3 miles of an environmental justice community
21    designated as of January 1, 2021 or an equity investment
22    eligible community. After January 1, 2035, each such EGU
23    and large greenhouse gas-emitting unit shall reduce its
24    CO2e emissions by at least 50% from its existing emissions
25    for CO2e, and shall be limited in operation to, on average,
26    6 hours or less per day, measured over a calendar year, and

 

 

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1    shall not run for more than 24 consecutive hours except in
2    emergency conditions, as designated by a Regional
3    Transmission Organization or Independent System Operator.
4        (3) No later than January 1, 2035: all EGUs and large
5    greenhouse gas-emitting units that began operation prior
6    to the effective date of this amendatory Act of the 102nd
7    General Assembly and have a NOx emission rate of less than
8    or equal to 0.12 lb/MWh and a SO2 emission rate less than
9    or equal to 0.006 lb/MWh, and are located in or within 3
10    miles of an environmental justice community designated as
11    of January 1, 2021 or an equity investment eligible
12    community. Each such EGU and large greenhouse gas-emitting
13    unit shall reduce its CO2e emissions by at least 50% from
14    its existing emissions for CO2e no later than January 1,
15    2030.
16        (4) No later than January 1, 2040: All remaining EGUs
17    and large greenhouse gas-emitting units that have a heat
18    rate greater than or equal to 7000 BTU/kWh. Each such EGU
19    and Large greenhouse gas-emitting unit shall reduce its
20    CO2e emissions by at least 50% from its existing emissions
21    for CO2e no later than January 1, 2035.
22        (5) No later than January 1, 2045: all remaining EGUs
23    and large greenhouse gas-emitting units.
24    (j) All EGUs and large greenhouse gas-emitting units that
25use gas as a fuel and are public GHG-emitting units shall
26permanently reduce all CO2e and copollutant emissions to zero,

 

 

10200SB3866ham004- 92 -LRB102 24630 LNS 38917 a

1including through unit retirement or the use of 100% green
2hydrogen or other similar technology that is commercially
3proven to achieve zero carbon emissions by January 1, 2045.
4    (k) All EGUs and large greenhouse gas-emitting units that
5utilize combined heat and power or cogeneration technology
6shall permanently reduce all CO2e and copollutant emissions to
7zero, including through unit retirement or the use of 100%
8green hydrogen or other similar technology that is
9commercially proven to achieve zero carbon emissions by
10January 1, 2045.
11    (k-5) No EGU or large greenhouse gas-emitting unit that
12uses gas as a fuel and is not a public GHG-emitting unit may
13emit, in any 12-month period, CO2e or copollutants in excess of
14that unit's existing emissions for those pollutants.
15    (l) Notwithstanding subsections (g) through (k-5), large
16GHG-emitting units including EGUs may temporarily continue
17emitting CO2e and copollutants greenhouse gases after any
18applicable deadline specified in any of subsections (g)
19through (k-5) if it has been determined, as described in
20paragraphs (1) and (2) of this subsection, that ongoing
21operation of the EGU is necessary to maintain power grid
22supply and reliability or ongoing operation of large
23GHG-emitting unit that is not an EGU is necessary to serve as
24an emergency backup to operations. Up to and including the
25occurrence of an emission reduction deadline under subsection
26(i), all EGUs and large GHG-emitting units must comply with

 

 

10200SB3866ham004- 93 -LRB102 24630 LNS 38917 a

1the following terms:
2        (1) if an EGU or large GHG-emitting unit that is a
3    participant in a regional transmission organization
4    intends to retire, it must submit documentation to the
5    appropriate regional transmission organization by the
6    appropriate deadline that meets all applicable regulatory
7    requirements necessary to obtain approval to permanently
8    cease operating the large GHG-emitting unit;
9        (2) if any EGU or large GHG-emitting unit that is a
10    participant in a regional transmission organization
11    receives notice that the regional transmission
12    organization has determined that continued operation of
13    the unit is required, the unit may continue operating
14    until the issue identified by the regional transmission
15    organization is resolved. The owner or operator of the
16    unit must cooperate with the regional transmission
17    organization in resolving the issue and must reduce its
18    emissions to zero, consistent with the requirements under
19    subsection (g), (h), (i), (j), (k), or (k-5), as
20    applicable, as soon as practicable when the issue
21    identified by the regional transmission organization is
22    resolved; and
23        (3) any large GHG-emitting unit that is not a
24    participant in a regional transmission organization shall
25    be allowed to continue emitting CO2e and copollutants
26    greenhouse gases after the zero-emission date specified in

 

 

10200SB3866ham004- 94 -LRB102 24630 LNS 38917 a

1    subsection (g), (h), (i), (j), (k), or (k-5), as
2    applicable, in the capacity of an emergency backup unit if
3    approved by the Illinois Commerce Commission.
4    (m) No variance, adjusted standard, or other regulatory
5relief otherwise available in this Act may be granted to the
6emissions reduction and elimination obligations in this
7Section.
8    (n) By June 30 of each year, beginning in 2025, the Agency
9shall prepare and publish on its website a report setting
10forth the actual greenhouse gas emissions from individual
11units and the aggregate statewide emissions from all units for
12the prior year.
13    (o) Every 5 years beginning in 2025, the Environmental
14Protection Agency, Illinois Power Agency, and Illinois
15Commerce Commission shall jointly prepare, and release
16publicly, a report to the General Assembly that examines the
17State's current progress toward its renewable energy resource
18development goals, the status of CO2e and copollutant
19emissions reductions, the current status and progress toward
20developing and implementing green hydrogen technologies, the
21current and projected status of electric resource adequacy and
22reliability throughout the State for the period beginning 5
23years ahead, and proposed solutions for any findings. The
24Environmental Protection Agency, Illinois Power Agency, and
25Illinois Commerce Commission shall consult PJM
26Interconnection, LLC and Midcontinent Independent System

 

 

10200SB3866ham004- 95 -LRB102 24630 LNS 38917 a

1Operator, Inc., or their respective successor organizations
2regarding forecasted resource adequacy and reliability needs,
3anticipated new generation interconnection, new transmission
4development or upgrades, and any announced large GHG-emitting
5unit closure dates and include this information in the report.
6The report shall be released publicly by no later than
7December 15 of the year it is prepared. If the Environmental
8Protection Agency, Illinois Power Agency, and Illinois
9Commerce Commission jointly conclude in the report that the
10data from the regional grid operators, the pace of renewable
11energy development, the pace of development of energy storage
12and demand response utilization, transmission capacity, and
13the CO2e and copollutant emissions reductions required by
14subsection (i) or (k-5) reasonably demonstrate that a resource
15adequacy shortfall will occur, including whether there will be
16sufficient in-state capacity to meet the zonal requirements of
17MISO Zone 4 or the PJM ComEd Zone, per the requirements of the
18regional transmission organizations, or that the regional
19transmission operators determine that a reliability violation
20will occur during the time frame the study is evaluating, then
21the Illinois Power Agency, in conjunction with the
22Environmental Protection Agency shall develop a plan to reduce
23or delay CO2e and copollutant emissions reductions
24requirements only to the extent and for the duration necessary
25to meet the resource adequacy and reliability needs of the
26State, including allowing any plants whose emission reduction

 

 

10200SB3866ham004- 96 -LRB102 24630 LNS 38917 a

1deadline has been identified in the plan as creating a
2reliability concern to continue operating, including operating
3with reduced emissions or as emergency backup where
4appropriate. The plan shall also consider the use of renewable
5energy, energy storage, demand response, transmission
6development, or other strategies to resolve the identified
7resource adequacy shortfall or reliability violation.
8        (1) In developing the plan, the Environmental
9    Protection Agency and the Illinois Power Agency shall hold
10    at least one workshop open to, and accessible at a time and
11    place convenient to, the public and shall consider any
12    comments made by stakeholders or the public. Upon
13    development of the plan, copies of the plan shall be
14    posted and made publicly available on the Environmental
15    Protection Agency's, the Illinois Power Agency's, and the
16    Illinois Commerce Commission's websites. All interested
17    parties shall have 60 days following the date of posting
18    to provide comment to the Environmental Protection Agency
19    and the Illinois Power Agency on the plan. All comments
20    submitted to the Environmental Protection Agency and the
21    Illinois Power Agency shall be encouraged to be specific,
22    supported by data or other detailed analyses, and, if
23    objecting to all or a portion of the plan, accompanied by
24    specific alternative wording or proposals. All comments
25    shall be posted on the Environmental Protection Agency's,
26    the Illinois Power Agency's, and the Illinois Commerce

 

 

10200SB3866ham004- 97 -LRB102 24630 LNS 38917 a

1    Commission's websites. Within 30 days following the end of
2    the 60-day review period, the Environmental Protection
3    Agency and the Illinois Power Agency shall revise the plan
4    as necessary based on the comments received and file its
5    revised plan with the Illinois Commerce Commission for
6    approval.
7        (2) Within 60 days after the filing of the revised
8    plan at the Illinois Commerce Commission, any person
9    objecting to the plan shall file an objection with the
10    Illinois Commerce Commission. Within 30 days after the
11    expiration of the comment period, the Illinois Commerce
12    Commission shall determine whether an evidentiary hearing
13    is necessary. The Illinois Commerce Commission shall also
14    host 3 public hearings within 90 days after the plan is
15    filed. Following the evidentiary and public hearings, the
16    Illinois Commerce Commission shall enter its order
17    approving or approving with modifications the reliability
18    mitigation plan within 180 days.
19        (3) The Illinois Commerce Commission shall only
20    approve the plan if the Illinois Commerce Commission
21    determines that it will resolve the resource adequacy or
22    reliability deficiency identified in the reliability
23    mitigation plan at the least amount of CO2e and copollutant
24    emissions, taking into consideration the emissions impacts
25    on environmental justice communities, and that it will
26    ensure adequate, reliable, affordable, efficient, and

 

 

10200SB3866ham004- 98 -LRB102 24630 LNS 38917 a

1    environmentally sustainable electric service at the lowest
2    total cost over time, taking into account the impact of
3    increases in emissions.
4        (4) If the resource adequacy or reliability deficiency
5    identified in the reliability mitigation plan is resolved
6    or reduced, the Environmental Protection Agency and the
7    Illinois Power Agency may file an amended plan adjusting
8    the reduction or delay in CO2e and copollutant emission
9    reduction requirements identified in the plan.
10(Source: P.A. 102-662, eff. 9-15-21.)
 
11
Article 99.

 
12    Section 99-99. Effective date. This Act takes effect upon
13becoming law.".