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

SB3866ham003 102ND GENERAL ASSEMBLY

Rep. Lawrence Walsh, Jr.

Filed: 4/5/2022

 

 


 

 


 
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1
AMENDMENT TO SENATE BILL 3866

2    AMENDMENT NO. ______. Amend Senate Bill 3866 by replacing
3everything after the enacting clause with the following:
 
4    "Section 5. The Energy Transition Act is amended by
5changing Section 5-40 as follows:
 
6    (20 ILCS 730/5-40)
7    (Section scheduled to be repealed on September 15, 2045)
8    Sec. 5-40. Illinois Climate Works Preapprenticeship
9Program.
10    (a) Subject to appropriation, the Department shall
11develop, and through Regional Administrators administer, the
12Illinois Climate Works Preapprenticeship Program. The goal of
13the Illinois Climate Works Preapprenticeship Program is to
14create a network of hubs throughout the State that will
15recruit, prescreen, and provide preapprenticeship skills
16training, for which participants may attend free of charge and

 

 

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

 

 

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

 

 

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1certifications relevant to clean energy jobs in the
2construction and building trades.
3        (1) recruit, prescreen, and provide preapprenticeship
4    training to equity investment eligible persons;
5        (2) provide training information related to
6    opportunities and certifications relevant to clean energy
7    jobs in the construction and building trades; and
8        (3) provide preapprentices with stipends they receive
9    that may vary depending on the occupation the individual
10    is training for.
11    (d-5) Priority shall be given to Climate Works Hubs that
12have an agreement with North American Building Trades Unions
13(NABTU) to utilize the Multi-Craft Core Curriculum or
14successor curriculums.
15    (e) Funding for the Program is subject to appropriation
16from the Energy Transition Assistance Fund.
17    (f) The Department shall adopt any rules deemed necessary
18to implement this Section.
19(Source: P.A. 102-662, eff. 9-15-21.)
 
20    Section 10. The Public Utilities Act is amended by
21changing Sections 5-117, 8-218, 16-107.6, 16-108.5, and
2216-108.30 and by adding Section 16-111.11 as follows:
 
23    (220 ILCS 5/5-117)
24    Sec. 5-117. Supplier diversity goals.

 

 

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1    (a) The public policy of this State is to collaboratively
2work with companies that serve Illinois residents to improve
3their supplier diversity in a non-antagonistic manner.
4    (b) The Commission shall require all gas, electric, and
5water utilities companies with at least 100,000 customers
6under its authority, as well as suppliers of wind energy,
7solar energy, hydroelectricity, nuclear energy, and any other
8supplier of energy within this State, to submit an annual
9report by April 15, 2015 and every April 15 thereafter, in a
10searchable Adobe PDF format, on all procurement goals and
11actual spending for female-owned, minority-owned,
12veteran-owned, and small business enterprises in the previous
13calendar year. These goals shall be expressed as a percentage
14of the total work performed by the entity submitting the
15report, and the actual spending for all female-owned,
16minority-owned, veteran-owned, and small business enterprises
17shall also be expressed as a percentage of the total work
18performed by the entity submitting the report.
19    (c) Each participating company in its annual report shall
20include the following information:
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 company shall be
25    actively seeking more participation in the next year;
26        (3.5) a buying plan for the specific goods and

 

 

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

 

 

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

 

 

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1least 5 years.
2(Source: P.A. 102-558, eff. 8-20-21; 102-662, eff. 9-15-21;
3102-673, eff. 11-30-21.)
 
4    (220 ILCS 5/8-218)
5    Sec. 8-218. Utility-scale pilot projects.
6    (a) Electric utilities serving greater than 500,000
7customers but less than 3,000,000 customers may propose, plan
8for, construct, install, control, own, manage, or operate up
9to 2 pilot projects consisting of utility-scale photovoltaic
10energy generation facilities. A pilot project may consist of
11photovoltaic energy generation facilities located on one or
12more sites and may be installed or constructed in phases.
13Energy storage facilities that are planned for, constructed,
14installed, controlled, owned, managed, or operated may be
15constructed in connection with the photovoltaic electricity
16generation pilot projects.
17    (b) Pilot projects shall be sited in equity investment
18eligible communities in or near the towns of Peoria and East
19St. Louis and must result in economic benefits for the members
20of the communities in which the project will be located. The
21amount paid per pilot project with or without energy storage
22facilities cannot exceed $20,000,000. The electric utility's
23costs of planning for, constructing, installing, controlling,
24owning, managing, or operating the photovoltaic electricity
25generation facilities and energy storage facilities may be

 

 

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

 

 

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

 

 

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1not limited to, electrochemical, thermal, and
2electromechanical technologies, and may be interconnected
3behind the customer's meter or interconnected behind its own
4meter.
5    "Smart inverter" means a device that converts direct
6current into alternating current and meets the IEEE 1547-2018
7equipment standards. Until devices that meet the IEEE
81547-2018 standard are available, devices that meet the UL
91741 SA standard are acceptable.
10    "Subscriber" has the meaning set forth in Section 1-10 of
11the Illinois Power Agency Act.
12    "Subscription" has the meaning set forth in Section 1-10
13of the Illinois Power Agency Act.
14    "System-wide grid services" means the benefits that a
15distributed energy resource provides to the distribution grid
16for a period of no less than 25 years. System-wide grid
17services do not vary by location, time, or the performance
18characteristics of the distributed energy resource.
19System-wide grid services include, but are not limited to,
20avoided or deferred distribution capacity costs, resilience
21and reliability benefits, avoided or deferred distribution
22operation and maintenance costs, distribution voltage and
23power quality benefits, and line loss reductions.
24    "Threshold date" means December 31, 2024 or the date on
25which the utility's tariff or tariffs setting the new
26compensation values established under subsection (e) take

 

 

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1effect, whichever is later.
2    (b) An electric utility that serves more than 200,000
3customers in the State shall file a petition with the
4Commission requesting approval of the utility's tariff to
5provide a rebate to the owner or operator of distributed
6generation, including third-party owned systems, that meets
7the following criteria:
8        (1) has a nameplate generating capacity no greater
9    than 5,000 kilowatts and is primarily used to offset a
10    customer's electricity load;
11        (2) is located on the customer's side of the billing
12    meter and for the customer's own use;
13        (3) is interconnected to electric distribution
14    facilities owned by the electric utility under rules
15    adopted by the Commission by means of the inverter or
16    smart inverter required by this Section, as applicable.
17    For purposes of this Section, "distributed generation"
18shall satisfy the definition of distributed renewable energy
19generation device set forth in Section 1-10 of the Illinois
20Power Agency Act to the extent such definition is consistent
21with the requirements of this Section.
22    In addition, any new photovoltaic distributed generation
23that is installed after June 1, 2017 (the effective date of
24Public Act 99-906) must be installed by a qualified person, as
25defined by subsection (i) of Section 1-56 of the Illinois
26Power Agency Act.

 

 

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

 

 

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1facilities paired with energy storage facilities on or
2adjacent to its premises for the benefits the facilities
3provide to the distribution grid. The tariff shall provide
4that, in addition to the other rebates identified in this
5Section, the electric utility shall rebate to such retail
6customer (i) the previously incurred and future costs of
7installing interconnection facilities and related
8infrastructure to enable full participation in the PJM
9Interconnection, LLC or its successor organization frequency
10regulation market; and (ii) all wholesale demand charges
11incurred after the effective date of this amendatory Act of
12the 102nd General Assembly. The Commission shall approve, or
13approve with modification, the tariff within 120 days after
14the utility's filing.
15    (c) The proposed tariff authorized by subsection (b) of
16this Section shall include the following participation terms
17for rebates to be applied under this Section for distributed
18generation that satisfies the criteria set forth in subsection
19(b) of this Section:
20        (1) The owner or operator of distributed generation
21    that services customers not eligible for net metering
22    under subsection (d), (d-5), or (e) of Section 16-107.5 of
23    this Act may apply for a rebate as provided for in this
24    Section. Until the threshold date, the value of the rebate
25    shall be $250 per kilowatt of nameplate generating
26    capacity, measured as nominal DC power output, of that

 

 

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1    customer's distributed generation. To the extent the
2    distributed generation also has an associated energy
3    storage, then the energy storage system shall be
4    separately compensated with a base rebate of $250 per
5    kilowatt-hour of nameplate capacity. Any distributed
6    generation device that is compensated for storage in this
7    subsection (1) before the threshold date shall participate
8    in one or more programs determined through the Multi-Year
9    Integrated Grid Planning process that are designed to meet
10    peak reduction and flexibility. After the threshold date,
11    the value of the base rebate and additional compensation
12    for any additive services shall be as determined by the
13    Commission in the proceeding described in subsection (e)
14    of this Section, provided that the value of the base
15    rebate for system-wide grid services shall not be lower
16    than $250 per kilowatt of nameplate generating capacity of
17    distributed generation or community renewable generation
18    project.
19        (2) The owner or operator of distributed generation
20    that, before the threshold date, would have been eligible
21    for net metering under subsection (d), (d-5), or (e) of
22    Section 16-107.5 of this Act and that has not previously
23    received a distributed generation rebate, may apply for a
24    rebate as provided for in this Section. Until the
25    threshold date, the value of the base rebate shall be $300
26    per kilowatt of nameplate generating capacity, measured as

 

 

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

 

 

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

 

 

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

 

 

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

 

 

10200SB3866ham003- 20 -LRB102 24630 AMQ 38763 a

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

 

 

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

 

 

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

 

 

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1subsection (e) of this Section, consistent with the following
2provisions:
3        (1) The utility shall defer the full amount of its
4    costs as a regulatory asset. The total costs deferred as a
5    regulatory asset shall be amortized over a 15-year period.
6    The unamortized balance shall be recognized as of December
7    31 for a given year. The utility shall also earn a return
8    on the total of the unamortized balance of the regulatory
9    assets, less any deferred taxes related to the unamortized
10    balance, at an annual rate equal to the utility's weighted
11    average cost of capital that includes, based on a year-end
12    capital structure, the utility's actual cost of debt for
13    the applicable calendar year and a cost of equity, which
14    shall be calculated as the sum of (i) the average for the
15    applicable calendar year of the monthly average yields of
16    30-year U.S. Treasury bonds published by the Board of
17    Governors of the Federal Reserve System in its weekly H.15
18    Statistical Release or successor publication; and (ii) 580
19    basis points, including a revenue conversion factor
20    calculated to recover or refund all additional income
21    taxes that may be payable or receivable as a result of that
22    return.
23        When an electric utility creates a regulatory asset
24    under the provisions of this paragraph (1) of subsection
25    (h), the costs are recovered over a period during which
26    customers also receive a benefit, which is in the public

 

 

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1    interest. Accordingly, it is the intent of the General
2    Assembly that an electric utility that elects to create a
3    regulatory asset under the provisions of this paragraph
4    (1) shall recover all of the associated costs, including,
5    but not limited to, its cost of capital as set forth in
6    this paragraph (1). After the Commission has approved the
7    prudence and reasonableness of the costs that comprise the
8    regulatory asset, the electric utility shall be permitted
9    to recover all such costs, and the value and
10    recoverability through rates of the associated regulatory
11    asset shall not be limited, altered, impaired, or reduced.
12    To enable the financing of the incremental capital
13    expenditures, including regulatory assets, for electric
14    utilities that serve less than 3,000,000 retail customers
15    but more than 500,000 retail customers in the State, the
16    utility's actual year-end capital structure that includes
17    a common equity ratio, excluding goodwill, of up to and
18    including 50% of the total capital structure shall be
19    deemed reasonable and used to set rates.
20        (2) The utility, at its election, may recover all of
21    the costs as part of a filing for a general increase in
22    rates under Article IX of this Act, as part of an annual
23    filing to update a performance-based formula rate under
24    subsection (d) of Section 16-108.5 of this Act, or through
25    an automatic adjustment clause tariff, provided that
26    nothing in this paragraph (2) permits the double recovery

 

 

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

 

 

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1    tariff.
2    (i) An electric utility shall recover from its retail
3customers, on a volumetric basis, all of the costs of the
4rebates made under a tariff or tariffs placed into effect
5under subsection (e) of this Section, including, but not
6limited to, the value of the rebates and all costs incurred by
7the utility to comply with and implement subsection (e) of
8this Section, consistent with the following provisions:
9        (1) The utility may defer a portion of its costs as a
10    regulatory asset. The Commission shall determine the
11    portion that may be appropriately deferred as a regulatory
12    asset. Factors that the Commission shall consider in
13    determining the portion of costs that shall be deferred as
14    a regulatory asset include, but are not limited to: (i)
15    whether and the extent to which a cost effectively
16    deferred or avoided other distribution system operating
17    costs or capital expenditures; (ii) the extent to which a
18    cost provides environmental benefits; (iii) the extent to
19    which a cost improves system reliability or resilience;
20    (iv) the electric utility's distribution system plan
21    developed pursuant to Section 16-105.17 of this Act; (v)
22    the extent to which a cost advances equity principles; and
23    (vi) such other factors as the Commission deems
24    appropriate. The remainder of costs shall be deemed an
25    operating expense and shall be recoverable if found
26    prudent and reasonable by the Commission.

 

 

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

 

 

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1    interest at an annual rate of return equal to the
2    utility's weighted average cost of capital as calculated
3    under paragraph (1) of this subsection (i), including a
4    revenue conversion factor calculated to recover or refund
5    all additional income taxes that may be payable or
6    receivable as a result of that return, of the revenue
7    requirement reflected in rates for each calendar year,
8    beginning with the calendar year in which the utility
9    files its automatic adjustment clause tariff under this
10    subsection (i), with what the revenue requirement would
11    have been had the actual cost information for the
12    applicable calendar year been available at the filing
13    date. The Commission shall review the proposed tariff and
14    may make changes to the tariff that are consistent with
15    this Section and with the Commission's authority under
16    Article IX of this Act, subject to notice and hearing.
17    Following notice and hearing, the Commission shall issue
18    an order approving, or approving with modification, such
19    tariff no later than 240 days after the utility files its
20    tariff.
21    (j) No later than 90 days after the Commission enters an
22order, or order on rehearing, whichever is later, approving an
23electric utility's proposed tariff under this Section, the
24electric utility shall provide notice of the availability of
25rebates under this Section.
26(Source: P.A. 102-662, eff. 9-15-21.)
 

 

 

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1    (220 ILCS 5/16-108.5)
2    Sec. 16-108.5. Infrastructure investment and
3modernization; regulatory reform.
4    (a) (Blank).
5    (b) For purposes of this Section, "participating utility"
6means an electric utility or a combination utility serving
7more than 1,000,000 customers in Illinois that voluntarily
8elects and commits to undertake (i) the infrastructure
9investment program consisting of the commitments and
10obligations described in this subsection (b) and (ii) the
11customer assistance program consisting of the commitments and
12obligations described in subsection (b-10) of this Section,
13notwithstanding any other provisions of this Act and without
14obtaining any approvals from the Commission or any other
15agency other than as set forth in this Section, regardless of
16whether any such approval would otherwise be required.
17"Combination utility" means a utility that, as of January 1,
182011, provided electric service to at least one million retail
19customers in Illinois and gas service to at least 500,000
20retail customers in Illinois. A participating utility shall
21recover the expenditures made under the infrastructure
22investment program through the ratemaking process, including,
23but not limited to, the performance-based formula rate and
24process set forth in this Section.
25    During the infrastructure investment program's peak

 

 

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1program year, a participating utility other than a combination
2utility shall create 2,000 full-time equivalent jobs in
3Illinois, and a participating utility that is a combination
4utility shall create 450 full-time equivalent jobs in Illinois
5related to the provision of electric service. These jobs shall
6include direct jobs, contractor positions, and induced jobs,
7but shall not include any portion of a job commitment, not
8specifically contingent on an amendatory Act of the 97th
9General Assembly becoming law, between a participating utility
10and a labor union that existed on December 30, 2011 (the
11effective date of Public Act 97-646) and that has not yet been
12fulfilled. A portion of the full-time equivalent jobs created
13by each participating utility shall include incremental
14personnel hired subsequent to December 30, 2011 (the effective
15date of Public Act 97-646). For purposes of this Section,
16"peak program year" means the consecutive 12-month period with
17the highest number of full-time equivalent jobs that occurs
18between the beginning of investment year 2 and the end of
19investment year 4.
20    A participating utility shall meet one of the following
21commitments, as applicable:
22        (1) Beginning no later than 180 days after a
23    participating utility other than a combination utility
24    files a performance-based formula rate tariff pursuant to
25    subsection (c) of this Section, or, beginning no later
26    than January 1, 2012 if such utility files such

 

 

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1    performance-based formula rate tariff within 14 days of
2    October 26, 2011 (the effective date of Public Act
3    97-616), the participating utility shall, except as
4    provided in subsection (b-5):
5            (A) over a 5-year period, invest an estimated
6        $1,300,000,000 in electric system upgrades,
7        modernization projects, and training facilities,
8        including, but not limited to:
9                (i) distribution infrastructure improvements
10            totaling an estimated $1,000,000,000, including
11            underground residential distribution cable
12            injection and replacement and mainline cable
13            system refurbishment and replacement projects;
14                (ii) training facility construction or upgrade
15            projects totaling an estimated $10,000,000,
16            provided that, at a minimum, one such facility
17            shall be located in a municipality having a
18            population of more than 2 million residents and
19            one such facility shall be located in a
20            municipality having a population of more than
21            150,000 residents but fewer than 170,000
22            residents; any such new facility located in a
23            municipality having a population of more than 2
24            million residents must be designed for the purpose
25            of obtaining, and the owner of the facility shall
26            apply for, certification under the United States

 

 

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

 

 

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

 

 

10200SB3866ham003- 34 -LRB102 24630 AMQ 38763 a

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

 

 

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1participating utility's annual capital investment program, as
2defined by, for purposes of this subsection (b), the
3participating utility's average capital spend for calendar
4years 2008, 2009, and 2010 as reported in the applicable
5Federal Energy Regulatory Commission (FERC) Form 1; provided
6that where one or more utilities have merged, the average
7capital spend shall be determined using the aggregate of the
8merged utilities' capital spend reported in FERC Form 1 for
9the years 2008, 2009, and 2010. A participating utility may
10add reasonable construction ramp-up and ramp-down time to the
11investment periods specified in this subsection (b). For each
12such investment period, the ramp-up and ramp-down time shall
13not exceed a total of 6 months.
14    Within 60 days after filing a tariff under subsection (c)
15of this Section, a participating utility shall submit to the
16Commission its plan, including scope, schedule, and staffing,
17for satisfying its infrastructure investment program
18commitments pursuant to this subsection (b). The submitted
19plan shall include a schedule and staffing plan for the next
20calendar year. The plan shall also include a plan for the
21creation, operation, and administration of a Smart Grid test
22bed as described in subsection (c) of Section 16-108.8. The
23plan need not allocate the work equally over the respective
24periods, but should allocate material increments throughout
25such periods commensurate with the work to be undertaken. No
26later than April 1 of each subsequent year, the utility shall

 

 

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1submit to the Commission a report that includes any updates to
2the plan, a schedule for the next calendar year, the
3expenditures made for the prior calendar year and
4cumulatively, and the number of full-time equivalent jobs
5created for the prior calendar year and cumulatively. If the
6utility is materially deficient in satisfying a schedule or
7staffing plan, then the report must also include a corrective
8action plan to address the deficiency. The fact that the plan,
9implementation of the plan, or a schedule changes shall not
10imply the imprudence or unreasonableness of the infrastructure
11investment program, plan, or schedule. Further, no later than
1245 days following the last day of the first, second, and third
13quarters of each year of the plan, a participating utility
14shall submit to the Commission a verified quarterly report for
15the prior quarter that includes (i) the total number of
16full-time equivalent jobs created during the prior quarter,
17(ii) the total number of employees as of the last day of the
18prior quarter, (iii) the total number of full-time equivalent
19hours in each job classification or job title, (iv) the total
20number of incremental employees and contractors in support of
21the investments undertaken pursuant to this subsection (b) for
22the prior quarter, and (v) any other information that the
23Commission may require by rule.
24    With respect to the participating utility's peak job
25commitment, if, after considering the utility's corrective
26action plan and compliance thereunder, the Commission enters

 

 

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1an order finding, after notice and hearing, that a
2participating utility did not satisfy its peak job commitment
3described in this subsection (b) for reasons that are
4reasonably within its control, then the Commission shall also
5determine, after consideration of the evidence, including, but
6not limited to, evidence submitted by the Department of
7Commerce and Economic Opportunity and the utility, the
8deficiency in the number of full-time equivalent jobs during
9the peak program year due to such failure. The Commission
10shall notify the Department of any proceeding that is
11initiated pursuant to this paragraph. For each full-time
12equivalent job deficiency during the peak program year that
13the Commission finds as set forth in this paragraph, the
14participating utility shall, within 30 days after the entry of
15the Commission's order, pay $6,000 to a fund for training
16grants administered under Section 605-800 of the Department of
17Commerce and Economic Opportunity Law, which shall not be a
18recoverable expense.
19    With respect to the participating utility's investment
20amount commitments, if, after considering the utility's
21corrective action plan and compliance thereunder, the
22Commission enters an order finding, after notice and hearing,
23that a participating utility is not satisfying its investment
24amount commitments described in this subsection (b), then the
25utility shall no longer be eligible to annually update the
26performance-based formula rate tariff pursuant to subsection

 

 

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

 

 

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1this Section and shall, as part of such investigation,
2determine whether the utility's actual costs under the program
3are prudent and reasonable. The fact that a participating
4utility invests more than the minimum amounts specified in
5subsection (b) of this Section or its plan shall not imply
6imprudence or unreasonableness.
7    If the participating utility finds that it is implementing
8its plan for satisfying the infrastructure investment program
9commitments described in subsection (b) of this Section at a
10cost below the estimated amounts specified in subsection (b)
11of this Section, then the utility may file a petition with the
12Commission requesting that it be permitted to satisfy its
13commitments by spending less than the estimated amounts
14specified in subsection (b) of this Section. The Commission
15shall, after notice and hearing, enter its order approving, or
16approving as modified, or denying each such petition within
17150 days after the filing of the petition.
18    In no event, absent General Assembly approval, shall the
19capital investment costs incurred by a participating utility
20other than a combination utility in satisfying its
21infrastructure investment program commitments described in
22subsection (b) of this Section exceed $3,000,000,000 or, for a
23participating utility that is a combination utility,
24$720,000,000. If the participating utility's updated cost
25estimates for satisfying its infrastructure investment program
26commitments described in subsection (b) of this Section exceed

 

 

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1the limitation imposed by this subsection (b-5), then it shall
2submit a report to the Commission that identifies the
3increased costs and explains the reason or reasons for the
4increased costs no later than the year in which the utility
5estimates it will exceed the limitation. The Commission shall
6review the report and shall, within 90 days after the
7participating utility files the report, report to the General
8Assembly its findings regarding the participating utility's
9report. If the General Assembly does not amend the limitation
10imposed by this subsection (b-5), then the utility may modify
11its plan so as not to exceed the limitation imposed by this
12subsection (b-5) and may propose corresponding changes to the
13metrics established pursuant to subparagraphs (5) through (8)
14of subsection (f) of this Section, and the Commission may
15modify the metrics and incremental savings goals established
16pursuant to subsection (f) of this Section accordingly.
17    (b-10) All participating utilities shall make
18contributions for an energy low-income and support program in
19accordance with this subsection. Beginning no later than 180
20days after a participating utility files a performance-based
21formula rate tariff pursuant to subsection (c) of this
22Section, or beginning no later than January 1, 2012 if such
23utility files such performance-based formula rate tariff
24within 14 days of December 30, 2011 (the effective date of
25Public Act 97-646), and without obtaining any approvals from
26the Commission or any other agency other than as set forth in

 

 

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1this Section, regardless of whether any such approval would
2otherwise be required, a participating utility other than a
3combination utility shall pay $10,000,000 per year for 5 years
4and a participating utility that is a combination utility
5shall pay $1,000,000 per year for 10 years to the energy
6low-income and support program, which is intended to fund
7customer assistance programs with the primary purpose being
8avoidance of imminent disconnection. Such programs may
9include:
10        (1) a residential hardship program that may partner
11    with community-based organizations, including senior
12    citizen organizations, and provides grants to low-income
13    residential customers, including low-income senior
14    citizens, who demonstrate a hardship;
15        (2) a program that provides grants and other bill
16    payment concessions to veterans with disabilities who
17    demonstrate a hardship and members of the armed services
18    or reserve forces of the United States or members of the
19    Illinois National Guard who are on active duty pursuant to
20    an executive order of the President of the United States,
21    an act of the Congress of the United States, or an order of
22    the Governor and who demonstrate a hardship;
23        (3) a budget assistance program that provides tools
24    and education to low-income senior citizens to assist them
25    with obtaining information regarding energy usage and
26    effective means of managing energy costs;

 

 

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

 

 

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1audit disbursement of the funds to ensure they were disbursed
2consistently with this Section.
3    If the Commission finds that a participating utility is no
4longer eligible to update the performance-based formula rate
5tariff pursuant to subsection (d) of this Section, or the
6performance-based formula rate is otherwise terminated, then
7the participating utility's voluntary commitments and
8obligations under this subsection (b-10) shall immediately
9terminate.
10    (c) A participating utility may elect to recover its
11delivery services costs through a performance-based formula
12rate approved by the Commission, which shall specify the cost
13components that form the basis of the rate charged to
14customers with sufficient specificity to operate in a
15standardized manner and be updated annually with transparent
16information that reflects the utility's actual costs to be
17recovered during the applicable rate year, which is the period
18beginning with the first billing day of January and extending
19through the last billing day of the following December. In the
20event the utility recovers a portion of its costs through
21automatic adjustment clause tariffs on October 26, 2011 (the
22effective date of Public Act 97-616), the utility may elect to
23continue to recover these costs through such tariffs, but then
24these costs shall not be recovered through the
25performance-based formula rate. In the event the participating
26utility, prior to December 30, 2011 (the effective date of

 

 

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1Public Act 97-646), filed electric delivery services tariffs
2with the Commission pursuant to Section 9-201 of this Act that
3are related to the recovery of its electric delivery services
4costs that are still pending on December 30, 2011 (the
5effective date of Public Act 97-646), the participating
6utility shall, at the time it files its performance-based
7formula rate tariff with the Commission, also file a notice of
8withdrawal with the Commission to withdraw the electric
9delivery services tariffs previously filed pursuant to Section
109-201 of this Act. Upon receipt of such notice, the Commission
11shall dismiss with prejudice any docket that had been
12initiated to investigate the electric delivery services
13tariffs filed pursuant to Section 9-201 of this Act, and such
14tariffs and the record related thereto shall not be the
15subject of any further hearing, investigation, or proceeding
16of any kind related to rates for electric delivery services.
17    The performance-based formula rate shall be implemented
18through a tariff filed with the Commission consistent with the
19provisions of this subsection (c) that shall be applicable to
20all delivery services customers. The Commission shall initiate
21and conduct an investigation of the tariff in a manner
22consistent with the provisions of this subsection (c) and the
23provisions of Article IX of this Act to the extent they do not
24conflict with this subsection (c). Except in the case where
25the Commission finds, after notice and hearing, that a
26participating utility is not satisfying its investment amount

 

 

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

 

 

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

 

 

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

 

 

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

 

 

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

 

 

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1    in subsection (d) of this Section, with interest, of the
2    revenue requirement reflected in rates for each calendar
3    year, beginning with the calendar year in which the
4    utility files its performance-based formula rate tariff
5    pursuant to subsection (c) of this Section, with what the
6    revenue requirement would have been had the actual cost
7    information for the applicable calendar year been
8    available at the filing date.
9    The utility shall file, together with its tariff, final
10data based on its most recently filed FERC Form 1, plus
11projected plant additions and correspondingly updated
12depreciation reserve and expense for the calendar year in
13which the tariff and data are filed, that shall populate the
14performance-based formula rate and set the initial delivery
15services rates under the formula. For purposes of this
16Section, "FERC Form 1" means the Annual Report of Major
17Electric Utilities, Licensees and Others that electric
18utilities are required to file with the Federal Energy
19Regulatory Commission under the Federal Power Act, Sections 3,
204(a), 304 and 209, modified as necessary to be consistent with
2183 Ill. Admin. Code Part 415 as of May 1, 2011. Nothing in this
22Section is intended to allow costs that are not otherwise
23recoverable to be recoverable by virtue of inclusion in FERC
24Form 1.
25    After the utility files its proposed performance-based
26formula rate structure and protocols and initial rates, the

 

 

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1Commission shall initiate a docket to review the filing. The
2Commission shall enter an order approving, or approving as
3modified, the performance-based formula rate, including the
4initial rates, as just and reasonable within 270 days after
5the date on which the tariff was filed, or, if the tariff is
6filed within 14 days after October 26, 2011 (the effective
7date of Public Act 97-616), then by May 31, 2012. Such review
8shall be based on the same evidentiary standards, including,
9but not limited to, those concerning the prudence and
10reasonableness of the costs incurred by the utility, the
11Commission applies in a hearing to review a filing for a
12general increase in rates under Article IX of this Act. The
13initial rates shall take effect within 30 days after the
14Commission's order approving the performance-based formula
15rate tariff.
16    Until such time as the Commission approves a different
17rate design and cost allocation pursuant to subsection (e) of
18this Section, rate design and cost allocation across customer
19classes shall be consistent with the Commission's most recent
20order regarding the participating utility's request for a
21general increase in its delivery services rates.
22    Subsequent changes to the performance-based formula rate
23structure or protocols shall be made as set forth in Section
249-201 of this Act, but nothing in this subsection (c) is
25intended to limit the Commission's authority under Article IX
26and other provisions of this Act to initiate an investigation

 

 

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

 

 

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

 

 

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

 

 

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

 

 

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

 

 

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1the performance-based formula rate approved pursuant to
2subsection (c) of this Section. In a proceeding under this
3subsection (d), the Commission shall enter its order no later
4than the earlier of 240 days after the utility's filing of its
5annual update of cost inputs to the performance-based formula
6rate or December 31. The Commission's determinations of the
7prudence and reasonableness of the costs incurred for the
8applicable calendar year shall be final upon entry of the
9Commission's order and shall not be subject to reopening,
10reexamination, or collateral attack in any other Commission
11proceeding, case, docket, order, rule or regulation, provided,
12however, that nothing in this subsection (d) shall prohibit a
13party from petitioning the Commission to rehear or appeal to
14the courts the order pursuant to the provisions of this Act.
15    In the event the Commission does not, either upon
16complaint or its own initiative, enter upon a hearing within
1745 days after the utility files the annual update of cost
18inputs to its performance-based formula rate, then the costs
19incurred for the applicable calendar year shall be deemed
20prudent and reasonable, and the filed charges shall not be
21subject to reopening, reexamination, or collateral attack in
22any other proceeding, case, docket, order, rule, or
23regulation.
24    A participating utility's first filing of the updated cost
25inputs, and any Commission investigation of such inputs
26pursuant to this subsection (d) shall proceed notwithstanding

 

 

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1the fact that the Commission's investigation under subsection
2(c) of this Section is still pending and notwithstanding any
3other law, order, rule, or Commission practice to the
4contrary.
5    (e) Nothing in subsections (c) or (d) of this Section
6shall prohibit the Commission from investigating, or a
7participating utility from filing, revenue-neutral tariff
8changes related to rate design of a performance-based formula
9rate that has been placed into effect for the utility.
10Following approval of a participating utility's
11performance-based formula rate tariff pursuant to subsection
12(c) of this Section, the utility shall make a filing with the
13Commission within one year after the effective date of the
14performance-based formula rate tariff that proposes changes to
15the tariff to incorporate the findings of any final rate
16design orders of the Commission applicable to the
17participating utility and entered subsequent to the
18Commission's approval of the tariff. The Commission shall,
19after notice and hearing, enter its order approving, or
20approving with modification, the proposed changes to the
21performance-based formula rate tariff within 240 days after
22the utility's filing. Following such approval, the utility
23shall make a filing with the Commission during each subsequent
243-year period that either proposes revenue-neutral tariff
25changes or re-files the existing tariffs without change, which
26shall present the Commission with an opportunity to suspend

 

 

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1the tariffs and consider revenue-neutral tariff changes
2related to rate design.
3    (f) Within 30 days after the filing of a tariff pursuant to
4subsection (c) of this Section, each participating utility
5shall develop and file with the Commission multi-year metrics
6designed to achieve, ratably (i.e., in equal segments) over a
710-year period, improvement over baseline performance values
8as follows:
9        (1) Twenty percent improvement in the System Average
10    Interruption Frequency Index, using a baseline of the
11    average of the data from 2001 through 2010.
12        (2) Fifteen percent improvement in the system Customer
13    Average Interruption Duration Index, using a baseline of
14    the average of the data from 2001 through 2010.
15        (3) For a participating utility other than a
16    combination utility, 20% improvement in the System Average
17    Interruption Frequency Index for its Southern Region,
18    using a baseline of the average of the data from 2001
19    through 2010. For purposes of this paragraph (3), Southern
20    Region shall have the meaning set forth in the
21    participating utility's most recent report filed pursuant
22    to Section 16-125 of this Act.
23        (3.5) For a participating utility other than a
24    combination utility, 20% improvement in the System Average
25    Interruption Frequency Index for its Northeastern Region,
26    using a baseline of the average of the data from 2001

 

 

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

 

 

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1        (8) Uncollectible expense: reduce uncollectible
2    expense by at least $30,000,000 for a participating
3    utility other than a combination utility and by at least
4    $3,500,000 for a participating utility that is a
5    combination utility, using a baseline of the average
6    uncollectible expense for the years 2008 through 2010.
7        (9) Opportunities for minority-owned and female-owned
8    business enterprises: design a performance metric
9    regarding the creation of opportunities for minority-owned
10    and female-owned business enterprises consistent with
11    State and federal law using a base performance value of
12    the percentage of the participating utility's capital
13    expenditures that were paid to minority-owned and
14    female-owned business enterprises in 2010.
15    The definitions set forth in 83 Ill. Admin. Code Part
16411.20 as of May 1, 2011 shall be used for purposes of
17calculating performance under paragraphs (1) through (3.5) of
18this subsection (f), provided, however, that the participating
19utility may exclude up to 9 extreme weather event days from
20such calculation for each year, and provided further that the
21participating utility shall exclude 9 extreme weather event
22days when calculating each year of the baseline period to the
23extent that there are 9 such days in a given year of the
24baseline period. For purposes of this Section, an extreme
25weather event day is a 24-hour calendar day (beginning at
2612:00 a.m. and ending at 11:59 p.m.) during which any weather

 

 

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1event (e.g., storm, tornado) caused interruptions for 10,000
2or more of the participating utility's customers for 3 hours
3or more. If there are more than 9 extreme weather event days in
4a year, then the utility may choose no more than 9 extreme
5weather event days to exclude, provided that the same extreme
6weather event days are excluded from each of the calculations
7performed under paragraphs (1) through (3.5) of this
8subsection (f).
9    The metrics shall include incremental performance goals
10for each year of the 10-year period, which shall be designed to
11demonstrate that the utility is on track to achieve the
12performance goal in each category at the end of the 10-year
13period. The utility shall elect when the 10-year period shall
14commence for the metrics set forth in subparagraphs (1)
15through (4) and (9) of this subsection (f), provided that it
16begins no later than 14 months following the date on which the
17utility begins investing pursuant to subsection (b) of this
18Section, and when the 10-year period shall commence for the
19metrics set forth in subparagraphs (5) through (8) of this
20subsection (f), provided that it begins no later than 14
21months following the date on which the Commission enters its
22order approving the utility's Advanced Metering Infrastructure
23Deployment Plan pursuant to subsection (c) of Section 16-108.6
24of this Act.
25    The metrics and performance goals set forth in
26subparagraphs (5) through (8) of this subsection (f) are based

 

 

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

 

 

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

 

 

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

 

 

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

 

 

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1impacted the utility's performance. Whenever a participating
2utility does not satisfy the metrics required pursuant to
3subsection (f) of this Section, the Commission shall, after
4notice and hearing, enter an order approving financial
5penalties in accordance with this subsection (f-5). The
6Commission-approved financial penalties shall be applied
7beginning with the next rate year. Nothing in this Section
8shall authorize the Commission to reduce or otherwise obviate
9the imposition of financial penalties for failing to achieve
10one or more of the metrics established pursuant to
11subparagraph (1) through (4) of subsection (f) of this
12Section.
13    (g) On or before July 31, 2014, each participating utility
14shall file a report with the Commission that sets forth the
15average annual increase in the average amount paid per
16kilowatthour for residential eligible retail customers,
17exclusive of the effects of energy efficiency programs,
18comparing the 12-month period ending May 31, 2012; the
1912-month period ending May 31, 2013; and the 12-month period
20ending May 31, 2014. For a participating utility that is a
21combination utility with more than one rate zone, the weighted
22average aggregate increase shall be provided. The report shall
23be filed together with a statement from an independent auditor
24attesting to the accuracy of the report. The cost of the
25independent auditor shall be borne by the participating
26utility and shall not be a recoverable expense. "The average

 

 

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1amount paid per kilowatthour" shall be based on the
2participating utility's tariffed rates actually in effect and
3shall not be calculated using any hypothetical rate or
4adjustments to actual charges (other than as specified for
5energy efficiency) as an input.
6    In the event that the average annual increase exceeds 2.5%
7as calculated pursuant to this subsection (g), then Sections
816-108.5, 16-108.6, 16-108.7, and 16-108.8 of this Act, other
9than this subsection, shall be inoperative as they relate to
10the utility and its service area as of the date of the report
11due to be submitted pursuant to this subsection and the
12utility shall no longer be eligible to annually update the
13performance-based formula rate tariff pursuant to subsection
14(d) of this Section. In such event, the then current rates
15shall remain in effect until such time as new rates are set
16pursuant to Article IX of this Act, subject to retroactive
17adjustment, with interest, to reconcile rates charged with
18actual costs, and the participating utility's voluntary
19commitments and obligations under subsection (b) of this
20Section shall immediately terminate, except for the utility's
21obligation to pay an amount already owed to the fund for
22training grants pursuant to a Commission order issued under
23subsection (b) of this Section.
24    In the event that the average annual increase is 2.5% or
25less as calculated pursuant to this subsection (g), then the
26performance-based formula rate shall remain in effect as set

 

 

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1forth in this Section.
2    For purposes of this Section, the amount per kilowatthour
3means the total amount paid for electric service expressed on
4a per kilowatthour basis, and the total amount paid for
5electric service includes without limitation amounts paid for
6supply, transmission, distribution, surcharges, and add-on
7taxes exclusive of any increases in taxes or new taxes imposed
8after October 26, 2011 (the effective date of Public Act
997-616). For purposes of this Section, "eligible retail
10customers" shall have the meaning set forth in Section
1116-111.5 of this Act.
12    The fact that this Section becomes inoperative as set
13forth in this subsection shall not be construed to mean that
14the Commission may reexamine or otherwise reopen prudence or
15reasonableness determinations already made.
16    (h) By December 31, 2017, the Commission shall prepare and
17file with the General Assembly a report on the infrastructure
18program and the performance-based formula rate. The report
19shall include the change in the average amount per
20kilowatthour paid by residential customers between June 1,
212011 and May 31, 2017. If the change in the total average rate
22paid exceeds 2.5% compounded annually, the Commission shall
23include in the report an analysis that shows the portion of the
24change due to the delivery services component and the portion
25of the change due to the supply component of the rate. The
26report shall include separate sections for each participating

 

 

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

 

 

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1or the delivery of broadband services,
2voice-over-internet-protocol services, telecommunications
3services, or cable or video programming services, unless they
4are part of a service directly related to delivery services or
5Smart Grid functionality or applications as defined in Section
616-108.6 of this Act, and from recovering the costs of such
7offerings from retail customers. This subsection is
8inoperative after December 31, 2027 for every participating
9utility.
10    (j) Nothing in this Section is intended to legislatively
11overturn the opinion issued in Commonwealth Edison Co. v. Ill.
12Commerce Comm'n, Nos. 2-08-0959, 2-08-1037, 2-08-1137,
131-08-3008, 1-08-3030, 1-08-3054, 1-08-3313 cons. (Ill. App.
14Ct. 2d Dist. Sept. 30, 2010). Public Act 97-616 shall not be
15construed as creating a contract between the General Assembly
16and the participating utility, and shall not establish a
17property right in the participating utility.
18    (k) The changes made in subsections (c) and (d) of this
19Section by Public Act 98-15 are intended to be a restatement
20and clarification of existing law, and intended to give
21binding effect to the provisions of House Resolution 1157
22adopted by the House of Representatives of the 97th General
23Assembly and Senate Resolution 821 adopted by the Senate of
24the 97th General Assembly that are reflected in paragraph (3)
25of this subsection. In addition, Public Act 98-15 preempts and
26supersedes any final Commission orders entered in Docket Nos.

 

 

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111-0721, 12-0001, 12-0293, and 12-0321 to the extent
2inconsistent with the amendatory language added to subsections
3(c) and (d).
4        (1) No earlier than 5 business days after May 22, 2013
5    (the effective date of Public Act 98-15), each
6    participating utility shall file any tariff changes
7    necessary to implement the amendatory language set forth
8    in subsections (c) and (d) of this Section by Public Act
9    98-15 and a revised revenue requirement under the
10    participating utility's performance-based formula rate.
11    The Commission shall enter a final order approving such
12    tariff changes and revised revenue requirement within 21
13    days after the participating utility's filing.
14        (2) Notwithstanding anything that may be to the
15    contrary, a participating utility may file a tariff to
16    retroactively recover its previously unrecovered actual
17    costs of delivery service that are no longer subject to
18    recovery through a reconciliation adjustment under
19    subsection (d) of this Section. This retroactive recovery
20    shall include any derivative adjustments resulting from
21    the changes to subsections (c) and (d) of this Section by
22    Public Act 98-15. Such tariff shall allow the utility to
23    assess, on current customer bills over a period of 12
24    monthly billing periods, a charge or credit related to
25    those unrecovered costs with interest at the utility's
26    weighted average cost of capital during the period in

 

 

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1    which those costs were unrecovered. A participating
2    utility may file a tariff that implements a retroactive
3    charge or credit as described in this paragraph for
4    amounts not otherwise included in the tariff filing
5    provided for in paragraph (1) of this subsection (k). The
6    Commission shall enter a final order approving such tariff
7    within 21 days after the participating utility's filing.
8        (3) The tariff changes described in paragraphs (1) and
9    (2) of this subsection (k) shall relate only to, and be
10    consistent with, the following provisions of Public Act
11    98-15: paragraph (2) of subsection (c) regarding year-end
12    capital structure, subparagraph (D) of paragraph (4) of
13    subsection (c) regarding pension assets, and subsection
14    (d) regarding the reconciliation components related to
15    year-end rate base and interest calculated at a rate equal
16    to the utility's weighted average cost of capital.
17        (4) Nothing in this subsection is intended to effect a
18    dismissal of or otherwise affect an appeal from any final
19    Commission orders entered in Docket Nos. 11-0721, 12-0001,
20    12-0293, and 12-0321 other than to the extent of the
21    amendatory language contained in subsections (c) and (d)
22    of this Section of Public Act 98-15.
23    (l) Each participating utility shall be deemed to have
24been in full compliance with all requirements of subsection
25(b) of this Section, subsection (c) of this Section, Section
2616-108.6 of this Act, and all Commission orders entered

 

 

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1pursuant to Sections 16-108.5 and 16-108.6 of this Act, up to
2and including May 22, 2013 (the effective date of Public Act
398-15). The Commission shall not undertake any investigation
4of such compliance and no penalty shall be assessed or adverse
5action taken against a participating utility for noncompliance
6with Commission orders associated with subsection (b) of this
7Section, subsection (c) of this Section, and Section 16-108.6
8of this Act prior to such date. Each participating utility
9other than a combination utility shall be permitted, without
10penalty, a period of 12 months after such effective date to
11take actions required to ensure its infrastructure investment
12program is in compliance with subsection (b) of this Section
13and with Section 16-108.6 of this Act. Provided further, the
14following subparagraphs shall apply to a participating utility
15other than a combination utility:
16        (A) if the Commission has initiated a proceeding
17    pursuant to subsection (e) of Section 16-108.6 of this Act
18    that is pending as of May 22, 2013 (the effective date of
19    Public Act 98-15), then the order entered in such
20    proceeding shall, after notice and hearing, accelerate the
21    commencement of the meter deployment schedule approved in
22    the final Commission order on rehearing entered in Docket
23    No. 12-0298;
24        (B) if the Commission has entered an order pursuant to
25    subsection (e) of Section 16-108.6 of this Act prior to
26    May 22, 2013 (the effective date of Public Act 98-15) that

 

 

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

 

 

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1consideration procurement times for meters and other equipment
2and operational issues. Nothing in Public Act 98-15 shall
3shorten or extend the end dates for the 5-year or 10-year
4periods set forth in subsection (b) of this Section or Section
516-108.6 of this Act. Nothing in this subsection is intended
6to address whether a participating utility has, or has not,
7satisfied any or all of the metrics and performance goals
8established pursuant to subsection (f) of this Section.
9    (m) The provisions of Public Act 98-15 are severable under
10Section 1.31 of the Statute on Statutes.
11(Source: P.A. 99-143, eff. 7-27-15; 99-642, eff. 7-28-16;
1299-906, eff. 6-1-17; 100-840, eff. 8-13-18.)
 
13    (220 ILCS 5/16-108.30)
14    Sec. 16-108.30. Energy Transition Assistance Fund.
15    (a) The Energy Transition Assistance Fund is hereby
16created as a special fund in the State Treasury. The Energy
17Transition Assistance Fund is authorized to receive moneys
18collected pursuant to this Section. Subject to appropriation,
19the Department of Commerce and Economic Opportunity shall use
20moneys from the Energy Transition Assistance Fund consistent
21with the purposes of this Act.
22    (b) An electric utility serving more than 500,000
23customers in the State shall assess an energy transition
24assistance charge on all its retail customers for the Energy
25Transition Assistance Fund. The utility's total charge shall

 

 

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1be set based upon the value determined by the Department of
2Commerce and Economic Opportunity pursuant to subsection (d)
3or (e), as applicable, of Section 605-1075 of the Department
4of Commerce and Economic Opportunity Law of the Civil
5Administrative Code of Illinois. For each utility, the charge
6shall be recovered through a single, uniform cents per
7kilowatt-hour charge applicable to all retail customers. For
8each utility, the charge shall not exceed 1.3% of the amount
9paid per kilowatthour by eligible retail those customers
10during the year ending May 31, 2009.
11    (c) Within 75 days of the effective date of this
12amendatory Act of the 102nd General Assembly, each electric
13utility serving more than 500,000 customers in the State shall
14file with the Illinois Commerce Commission tariffs
15incorporating the energy transition assistance charge in other
16charges stated in such tariffs, which energy transition
17assistance charges shall become effective no later than the
18beginning of the first billing cycle that begins on or after
19January 1, 2022. Each electric utility serving more than
20500,000 customers in the State shall, prior to the beginning
21of each calendar year starting with calendar year 2023, file
22with the Illinois Commerce Commission tariff revisions to
23incorporate annual revisions to the energy transition
24assistance charge as prescribed by the Department of Commerce
25and Economic Opportunity pursuant to Section 605-1075 of the
26Department of Commerce and Economic Opportunity Law of the

 

 

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1Civil Administrative Code of Illinois so that such revision
2becomes effective no later than the beginning of the first
3billing cycle in each respective year.
4    (d) The energy transition assistance charge shall be
5considered a charge for public utility service.
6    (e) By the 20th day of the month following the month in
7which the charges imposed by this Section were collected, each
8electric utility serving more than 500,000 customers in the
9State shall remit to Department of Revenue all moneys received
10as payment of the energy transition assistance charge on a
11return prescribed and furnished by the Department of Revenue
12showing such information as the Department of Revenue may
13reasonably require. If a customer makes a partial payment, a
14public utility may apply such partial payments first to
15amounts owed to the utility. No customer may be subjected to
16disconnection of his or her utility service for failure to pay
17the energy transition assistance charge.
18    If any payment provided for in this subsection exceeds the
19electric utility's liabilities under this Act, as shown on an
20original return, the Department may authorize the electric
21utility to credit such excess payment against liability
22subsequently to be remitted to the Department under this Act,
23in accordance with reasonable rules adopted by the Department.
24    All the provisions of Sections 4, 5, 5a, 5b, 5c, 5d, 5e,
255f, 5g, 5i, 5j, 6, 6a, 6b, 6c, 7, 8, 9, 10, 11, 11a, 12, and 13
26of the Retailers' Occupation Tax Act that are not inconsistent

 

 

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1with this Act apply, as far as practicable, to the charge
2imposed by this Act to the same extent as if those provisions
3were included in this Act. References in the incorporated
4Sections of the Retailers' Occupation Tax Act to retailers, to
5sellers, or to persons engaged in the business of selling
6tangible personal property mean persons required to remit the
7charge imposed under this Act.
8    (f) The Department of Revenue shall deposit into the
9Energy Transition Assistance Fund all moneys remitted to it in
10accordance with this Section.
11    (g) The Department of Revenue may establish such rules as
12it deems necessary to implement this Section.
13    (h) The Department of Commerce and Economic Opportunity
14may establish such rules as it deems necessary to implement
15this Section.
16(Source: P.A. 102-662, eff. 9-15-21.)
 
17    (220 ILCS 5/16-111.11 new)
18    Sec. 16-111.11. Supplier diversity reporting for
19non-utilities.
20    (a) The following entities shall submit an annual supplier
21diversity report to the Commission for a given year:
22        (1) entities that received a contract to provide more
23    than 10,000 renewable energy credits approved by the
24    Commission in a given year pursuant to subparagraph (iii)
25    of paragraph (5) of subsection (b) of Section 16-111.5;

 

 

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1        (2) entities that received a contract to provide more
2    than 10,000 renewable energy credits approved by the
3    Commission in a given year pursuant to subsection (e) of
4    Section 16-111.5;
5        (3) alternative retail electric suppliers that have
6    yearly sales in the State of 1,000,000,000 kilowatt hours
7    or more, and alternative gas suppliers as defined in
8    Section 19-105 that have yearly sales in the State of
9    1,000,000 dekatherms or more;
10        (4) entities constructing or operating an HVDC
11    transmission line as defined in Section 1-10 of the
12    Illinois Power Agency Act or entities constructing or
13    operating transmission facilities under a certificate of
14    public convenience and necessity issued pursuant to
15    subsection (b-5) of Section 8-406;
16        (5) entities installing more than 100 energy
17    efficiency measures with a certificate approved by the
18    Commission pursuant to Section 16-128B; and
19        (6) other suppliers of electricity generated from any
20    resource, including, but not limited to, hydro, nuclear,
21    coal, natural gas, and any other supplier of energy within
22    this State.
23    (b) An annual report filed pursuant to this Section shall
24be filed on an electronic form as designed by the Commission by
25June 1, 2023 and every June 1 thereafter, in a searchable Adobe
26PDF format, on all procurement goals and actual spending for

 

 

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

 

 

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1        (5) an explanation of the challenges faced in finding
2    quality vendors and offer any suggestions for what the
3    Commission could do to be helpful to identify those
4    vendors;
5        (6) a list of the certifications the entity
6    recognizes;
7        (7) the point of contact for any potential vendor who
8    wants to do business with the entity and explain the
9    process for a vendor to enroll with the company as a
10    minority-owned, women-owned, or veteran-owned company; and
11        (8) any particular success stories to encourage other
12    entities to emulate best practices.
13    (c) Each annual report shall include as much
14State-specific data as possible. If the submitting entity does
15not submit State-specific data, then the entity shall include
16any national data it does have and explain why it could not
17submit State-specific data and how it intends to do so in
18future reports.
19    (d) Each annual report shall include the rules,
20regulations, and definitions used for the procurement goals in
21the entity's annual report.
22    (e) Each annual report filed or submitted under this
23Section shall be submitted with the Commission. The Commission
24shall not be required or authorized to compel production of
25any report under this Section. The Commission shall hold an
26annual workshop open to the public in 2024 and every year

 

 

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

 

 

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

 

 

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1system that, either simultaneously or sequentially, produces
2electricity and useful thermal energy from a single fuel
3source.
4    "Copollutants" refers to the 6 criteria pollutants that
5have been identified by the United States Environmental
6Protection Agency pursuant to the Clean Air Act.
7    "Electric generating unit" or "EGU" means a fossil
8fuel-fired stationary boiler, combustion turbine, or combined
9cycle system that serves a generator that has a nameplate
10capacity greater than 25 MWe and produces electricity for
11sale.
12    "Environmental justice community" means the definition of
13that term based on existing methodologies and findings, used
14and as may be updated by the Illinois Power Agency and its
15program administrator in the Illinois Solar for All Program.
16    "Equity investment eligible community" or "eligible
17community" means the geographic areas throughout Illinois that
18would most benefit from equitable investments by the State
19designed to combat discrimination and foster sustainable
20economic growth. Specifically, eligible community means the
21following areas:
22        (1) areas where residents have been historically
23    excluded from economic opportunities, including
24    opportunities in the energy sector, as defined as R3 areas
25    pursuant to Section 10-40 of the Cannabis Regulation and
26    Tax Act; and

 

 

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1        (2) areas where residents have been historically
2    subject to disproportionate burdens of pollution,
3    including pollution from the energy sector, as established
4    by environmental justice communities as defined by the
5    Illinois Power Agency pursuant to the Illinois Power
6    Agency Act, excluding any racial or ethnic indicators.
7    "Equity investment eligible person" or "eligible person"
8means the persons who would most benefit from equitable
9investments by the State designed to combat discrimination and
10foster sustainable economic growth. Specifically, eligible
11person means the following people:
12        (1) persons whose primary residence is in an equity
13    investment eligible community;
14        (2) persons whose primary residence is in a
15    municipality, or a county with a population under 100,000,
16    where the closure of an electric generating unit or mine
17    has been publicly announced or the electric generating
18    unit or mine is in the process of closing or closed within
19    the last 5 years;
20        (3) persons who are graduates of or currently enrolled
21    in the foster care system; or
22        (4) persons who were formerly incarcerated.
23    "Existing emissions" means:
24        (1) for CO2e, the total average tons-per-year of CO2e
25    emitted by the EGU or large GHG-emitting unit either in
26    the years 2018 through 2020 or, if the unit was not yet in

 

 

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

 

 

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1GHG-emitting unit" means large greenhouse gas-emitting units,
2including EGUs, that are wholly owned, directly or indirectly,
3by one or more municipalities, municipal corporations, joint
4municipal electric power agencies, electric cooperatives, or
5other governmental or nonprofit entities, whether organized
6and created under the laws of Illinois or another state.
7    "SO2 emission rate" means the "plant annual SO2 total
8output emission rate" as measured by the United States
9Environmental Protection Agency in its Emissions & Generation
10Resource Integrated Database (eGrid), or its successor, in the
11most recent year for which data is available.
12    (g) All EGUs and large greenhouse gas-emitting units that
13use coal or oil as a fuel and are not public GHG-emitting units
14shall permanently reduce all CO2e and copollutant emissions to
15zero no later than January 1, 2030.
16    (h) All EGUs and large greenhouse gas-emitting units that
17use coal as a fuel and are public GHG-emitting units shall
18permanently reduce CO2e emissions to zero no later than
19December 31, 2045. Any source or plant with such units must
20also reduce their CO2e emissions by 45% from existing
21emissions by no later than January 1, 2035. If the emissions
22reduction requirement is not achieved by December 31, 2035,
23the plant shall retire one or more units or otherwise reduce
24its CO2e emissions by 45% from existing emissions by June 30,
252038.
26    (i) All EGUs and large greenhouse gas-emitting units that

 

 

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

 

 

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1    Transmission Organization or Independent System Operator.
2        (3) No later than January 1, 2035: all EGUs and large
3    greenhouse gas-emitting units that began operation prior
4    to the effective date of this amendatory Act of the 102nd
5    General Assembly and have a NOx emission rate of less than
6    or equal to 0.12 lb/MWh and a SO2 emission rate less than
7    or equal to 0.006 lb/MWh, and are located in or within 3
8    miles of an environmental justice community designated as
9    of January 1, 2021 or an equity investment eligible
10    community. Each such EGU and large greenhouse gas-emitting
11    unit shall reduce its CO2e emissions by at least 50% from
12    its existing emissions for CO2e no later than January 1,
13    2030.
14        (4) No later than January 1, 2040: All remaining EGUs
15    and large greenhouse gas-emitting units that have a heat
16    rate greater than or equal to 7000 BTU/kWh. Each such EGU
17    and Large greenhouse gas-emitting unit shall reduce its
18    CO2e emissions by at least 50% from its existing emissions
19    for CO2e no later than January 1, 2035.
20        (5) No later than January 1, 2045: all remaining EGUs
21    and large greenhouse gas-emitting units.
22    (j) All EGUs and large greenhouse gas-emitting units that
23use gas as a fuel and are public GHG-emitting units shall
24permanently reduce all CO2e and copollutant emissions to zero,
25including through unit retirement or the use of 100% green
26hydrogen or other similar technology that is commercially

 

 

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

 

 

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

 

 

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

 

 

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

 

 

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1with reduced emissions or as emergency backup where
2appropriate. The plan shall also consider the use of renewable
3energy, energy storage, demand response, transmission
4development, or other strategies to resolve the identified
5resource adequacy shortfall or reliability violation.
6        (1) In developing the plan, the Environmental
7    Protection Agency and the Illinois Power Agency shall hold
8    at least one workshop open to, and accessible at a time and
9    place convenient to, the public and shall consider any
10    comments made by stakeholders or the public. Upon
11    development of the plan, copies of the plan shall be
12    posted and made publicly available on the Environmental
13    Protection Agency's, the Illinois Power Agency's, and the
14    Illinois Commerce Commission's websites. All interested
15    parties shall have 60 days following the date of posting
16    to provide comment to the Environmental Protection Agency
17    and the Illinois Power Agency on the plan. All comments
18    submitted to the Environmental Protection Agency and the
19    Illinois Power Agency shall be encouraged to be specific,
20    supported by data or other detailed analyses, and, if
21    objecting to all or a portion of the plan, accompanied by
22    specific alternative wording or proposals. All comments
23    shall be posted on the Environmental Protection Agency's,
24    the Illinois Power Agency's, and the Illinois Commerce
25    Commission's websites. Within 30 days following the end of
26    the 60-day review period, the Environmental Protection

 

 

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

 

 

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1    increases in emissions.
2        (4) If the resource adequacy or reliability deficiency
3    identified in the reliability mitigation plan is resolved
4    or reduced, the Environmental Protection Agency and the
5    Illinois Power Agency may file an amended plan adjusting
6    the reduction or delay in CO2e and copollutant emission
7    reduction requirements identified in the plan.
8(Source: P.A. 102-662, eff. 9-15-21.)
 
9    Section 99. Effective date. This Act takes effect upon
10becoming law.".