State of Illinois
2021 and 2022


Introduced 2/26/2021, by Sen. Ann Gillespie


See Index

    Creates the Public Utilities Intervenor Compensation Act. Provides that the Illinois Commerce Commission shall award reasonable advocate's fees, reasonable expert witness fees, and other reasonable costs of preparation for and participation in a hearing or proceeding to a customer that complies with specified procedures and makes a contribution to the adoption of the Commission's order or decision and participation or intervention without an award of fees or costs imposes a significant financial hardship. Creates provisions concerning procedures; calculation of awards; payments and cost recovery; denial of payments; the Illinois Commerce Commission Intervenor Compensation Fund; pre-proceeding grants; and rulemaking. Amends the State Finance Act to create the Illinois Commerce Commission Intervenor Compensation Fund. Makes conforming changes in the Illinois Administrative Procedure Act and the State Finance Act. Amends the Public Utilities Act. Creates provisions concerning restitution for misconduct; the Multi-Year Integrated Grid Plan; residential time-of-use pricing; and performance-based ratemaking. Makes changes in provisions concerning the Illinois Commerce Commission; donations; natural gas surcharges; and public hearings. Makes other changes. Effective immediately.

LRB102 17361 SPS 22854 b






SB2295LRB102 17361 SPS 22854 b

1    AN ACT concerning regulation.
2    Be it enacted by the People of the State of Illinois,
3represented in the General Assembly:
4    Section 1. Short title. This Act may be cited as the Public
5Utilities Intervenor Compensation Act.
6    Section 5. Findings. The General Assembly finds that:
7        (1) public participation is an important consideration
8    in Illinois Commerce Commission proceedings;
9        (2) public stakeholders face financial challenges in
10    participating at Illinois Commerce Commission proceedings,
11    including retaining legal representation and expert
12    witnesses;
13        (3) it is in the public interest to reduce barriers to
14    participation in Illinois Commerce Commission proceedings,
15    particularly for environmental justice and other public
16    interest organizations;
17        (4) provision of compensation for participating
18    organizations will improve Illinois Commerce Commission
19    proceedings and decisions, increase public engagement, and
20    encourage additional transparency.
21    Section 10. Definitions. As used in this Act:
22    "Commission" means the Illinois Commerce Commission.



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1    "Compensation" means payment for all or part, as
2determined by the Commission, of reasonable advocate's fees,
3reasonable expert witness fees, and other reasonable costs of
4preparation for and participation in a proceeding, and
5includes the fees and costs of obtaining an award under this
6Article and of obtaining judicial review, if any.
7    "Contribution" means that the customer's presentation has
8met the following standard:
9        (1) For any customer, the presentation has assisted
10    the Commission in the making of its order or decision
11    because the order or decision has adopted in whole or in
12    part one or more factual contentions, legal contentions,
13    or specific policy or procedural recommendations presented
14    by the customer. For any customer, where the customer's
15    participation has resulted in a contribution, even if the
16    decision adopts that customer's contention or
17    recommendations only in part, the Commission may award the
18    customer compensation for all reasonable advocate's fees,
19    reasonable expert fees, and other reasonable costs
20    incurred by the customer in preparing or presenting that
21    contention or recommendation. Participation by any
22    customer that materially supplements, complements, or
23    contributes to the presentation of another party,
24    including the Commission staff, that makes a contribution
25    to a Commission order or decision is fully eligible for
26    compensation.



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1        (2) For customers with fewer than 3 attorneys on
2    staff, the customer introduces a relevant argument or
3    factual evidence into the docket, garners a response from
4    another party to the proceeding, and files briefs.
5        (3) For customers without attorneys on staff, the
6    customer introduces a relevant argument or factual
7    evidence into the docket.
8    "Customer" means any of the following:
9        (1) A participant representing consumers, customers,
10    or subscribers of any electrical, gas, telephone, or water
11    corporation that is subject to the jurisdiction of the
12    Commission.
13        (2) A representative who has been authorized by a
14    customer.
15        (3) A representative of a group or organization
16    authorized pursuant to its articles of incorporation or
17    bylaws to represent the interests of residential
18    customers, or to represent small commercial customers who
19    receive bundled electric service from an electrical
20    corporation.
21        (4) an organization representing environmental justice
22    communities.
23    "Customer" does not include any state, federal, or local
24governmental agency, or any publicly owned public utility.
25"Customer" must be a nonprofit organization.
26    "Environmental justice communities" means the definition



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1of that term based on existing methodologies and findings,
2used and as may be updated by the Illinois Power Agency and its
3program administrator in the Illinois Solar for All Program.
4    "Expert witness fees" means recorded or billed costs
5incurred by a customer for an expert witness.
6    "Other reasonable costs" means reasonable out-of-pocket
7expenses directly incurred by a customer that are directly
8related to the contentions or recommendations made by the
9customer that resulted in a contribution.
10    "Party" means any interested party, respondent public
11utility, or Commission staff in a hearing or proceeding.
12    "Public utility" has the meaning ascribed to it in the
13Public Utilities Act.
14    "Significant financial hardship" means either that the
15customer cannot afford, without undue hardship, to pay the
16costs of effective participation, including advocate's fees,
17expert witness fees, and other reasonable costs of
18participation, or that, in the case of a group or
19organization, the economic interest of the individual members
20of the group or organization is small in comparison to the
21costs of effective participation in the proceeding.
22    Section 15. Intervenor compensation awards. The Commission
23shall award reasonable advocate's fees, reasonable expert
24witness fees, and other reasonable costs of preparation for
25and participation in a hearing or proceeding to any customer



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1that complies with the procedures in Section 20 and satisfies
2both of the following requirements:
3        (1) The customer's presentation makes a contribution
4    to the adoption, in whole or in part, of the Commission's
5    order or decision, as described in subsection (b) of
6    Section 20; and
7        (2) Participation or intervention without an award of
8    fees or costs imposes a significant financial hardship.
9    Section 20. Intervenor compensation award procedures.
10    (a)(1) A customer that intends to seek an award under this
11Article shall, within 30 days after the prehearing conference
12is held, file and serve on all parties to the proceeding a
13notice of intent to claim compensation. The Commission shall
14determine the procedure to be used in cases in which:
15        (i) no prehearing conference is scheduled;
16        (ii) the Commission anticipates that the proceeding
17    will take less than 30 days;
18        (iii) the schedule would not reasonably allow parties
19    to identify issues within the time frame set forth in this
20    subsection; or
21        (iv) where new issues emerge after the time set for
22    filing.
23    (2)(i) The notice of intent to claim compensation shall
24include both of the following:
25        (A) A statement of the nature and extent of the



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1    customer's planned participation in the proceeding as far
2    as it is possible to set it out when the notice of intent
3    is filed.
4        (B) An itemized estimate of the compensation that the
5    customer expects to request, given the likely duration of
6    the proceeding as it appears at the time.
7    (ii) The notice of intent may also include a showing by the
8customer that participation in the hearing or proceeding would
9pose a significant financial hardship. Alternatively, such a
10showing shall be included in the request submitted pursuant to
11subsection (c).
12    (3) Within 15 days after service of the notice of intent to
13claim compensation, the administrative law judge may direct
14the staff, and may permit any other interested party, to file a
15statement responding to the notice.
16    (b)(1) If the customer's showing of significant financial
17hardship was included in the notice filed pursuant to
18subsection (a), the administrative law judge shall issue
19within 30 days thereafter a preliminary ruling addressing
20whether the customer is eligible for an award of compensation.
21The ruling shall address whether a showing of significant
22financial hardship has been made. A finding of significant
23financial hardship shall create a rebuttable presumption of
24eligibility for compensation in other Commission proceedings
25commencing within 2 years after the date of that finding.
26    (2) The administrative law judge may, in any event, issue



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1a ruling addressing issues raised by the notice of intent to
2claim compensation. The ruling may point out similar
3positions, areas of potential duplication in showings,
4unrealistic expectation for compensation, and any other matter
5that may affect the customer's ultimate claim for
6compensation. Failure of the ruling to point out similar
7positions or potential duplication or any other potential
8impact on the ultimate claim for compensation shall not imply
9approval of any claim for compensation. A finding of
10significant financial hardship in no way ensures compensation.
11Similarly, the failure of the customer to identify a specific
12issue in the notice of intent or to precisely estimate
13potential compensation shall not preclude an award of
14reasonable compensation if a contribution is made.
15    (c) Following issuance of a final order or decision by the
16Commission in the hearing or proceeding, a customer that has
17been found, pursuant to subsection (b), to be eligible for an
18award of compensation may file within 60 days a request for an
19award. The request shall include at a minimum a detailed
20description of services and expenditures and a description of
21the customer's contribution to the hearing or proceeding.
22Within 30 days after service of the request, the Commission
23staff may file, and any other party may file, a response to the
25    (d) The Commission may audit the records and books of the
26customer to the extent necessary to verify the basis for the



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1award. The Commission shall preserve the confidentiality of
2the customer's records in making its audit. Within 20 days
3after completion of the audit, if any, the Commission shall
4direct that an audit report shall be prepared and filed. Any
5other party may file a response to the audit report within 20
6days thereafter.
7    (e) Within 75 days after the filing of a request for
8compensation pursuant to subsection (c), or within 50 days
9after the filing of an audit report, whichever occurs later,
10the Commission shall issue a decision that determines whether
11or not the customer has made a contribution to the final order
12or decision in the hearing or proceeding. If the Commission
13finds that the customer requesting compensation has made a
14contribution, the Commission shall describe this contribution
15and shall determine the amount of compensation to be paid.
16    Section 25. Calculation of intervenor compensation awards.
17The computation of compensation awarded shall take into
18consideration the market rates paid to persons of comparable
19training and experience who offer similar services. The
20compensation awarded may not exceed the comparable market rate
21for services paid by the Commission or the public utility,
22whichever is greater, to persons of comparable training and
23experience who are offering similar services.
24    Section 30. Intervenor compensation payments and cost



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1recovery. An award made under this Act shall be paid by the
2public utility that is the subject of the hearing,
3investigation, or proceeding, as determined by the Commission,
4within 30 days. Notwithstanding any other law, an award paid
5by a public utility pursuant to this Act shall be allowed by
6the Commission as an expense for the purpose of establishing
7rates of the public utility.
8    Section 35. Denial of intervenor compensation payments.
9The Commission shall deny any award to any customer that
10attempts to delay or obstruct the orderly and timely
11fulfillment of the Commission's responsibilities.
12    Section 40. Illinois Commerce Commission Intervenor
13Compensation Fund. The Illinois Commerce Commission Intervenor
14Compensation Fund is hereby created as a special fund in the
15State treasury. The Commission shall administer the Illinois
16Commerce Commission Intervenor Compensation Fund for use as
17described in Section 45. An electric public utility with
183,000,000 or more retail customers shall contribute $450,000
19to the Illinois Commerce Commission Intervenor Compensation
20Fund within 60 days after the effective date of this Act. A
21combined electric and gas public utility serving fewer than
223,000,000 but more than 500,000 retail customers shall
23contribute $225,000 to the Illinois Commerce Commission
24Intervenor Compensation Fund within 60 days after the



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1effective date of this Act. A gas public utility with
22,000,000 or more retail customers that is not a combined
3electric and gas public utility shall contribute $225,000 to
4the Illinois Commerce Commission Intervenor Compensation Fund
5within 60 days after the effective date of this Act. A gas
6public utility with fewer than 2,000,000 retail customers but
7more than 300,000 retail customers that is not a combined
8electric and gas public utility shall contribute $80,000 to
9the Illinois Commerce Commission Intervenor Compensation Fund
10within 60 days after the effective date of this Act. A gas
11public utility with fewer than 300,000 retail customers that
12is not a combined electric and gas public utility shall
13contribute $20,000 to the Illinois Commerce Commission
14Intervenor Compensation Fund within 60 days after the
15effective date of this Act.
16    Section 45. Intervenor compensation pre-proceeding grants.
17    (a) Any customer that applies for intervenor compensation
18payments under subsection (a) of Section 20 may also, at the
19same time, apply for a grant from the Illinois Commerce
20Commission Intervenor Compensation Fund for the costs
21described in its notice of intent to claim compensation. A
22final decision regarding the grant shall be made at the time of
23the preliminary ruling on intervenor compensation eligibility
24in subsection (b) of Section 20. No pre-proceeding grant shall
25be given to organizations who are not found to be eligible for



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1intervenor compensation. If granted, payments must be made
2within 30 days to facilitate participation in the proceeding.
3At the time of the final decision regarding the grant, the
4Commission shall notify the customer of the requirements to be
5awarded intervenor compensation and that, if the customer does
6not prevail in receiving intervenor compensation of at least
7the amount of the grant, the customer will be expected to
8reimburse the Illinois Commerce Commission Intervenor
9Compensation Fund for the remaining grant moneys on a regular
10schedule within 5 years of the end of the proceeding. After
11notification, the customer may accept or deny receipt of the
13    (b) To apply for a grant from the Illinois Commerce
14Commission Intervenor Compensation Fund, the customer must
15describe why prepayment of intervenor compensation is
16necessary for it to participate in the proceeding and show
17financial hardship sufficient that the customer cannot
18reasonably be expected to participate without receiving a
20    (c) If a customer that receives a grant from the Illinois
21Commerce Commission Intervenor Compensation Fund subsequently
22prevails in receiving intervenor compensation, the public
23utility paying intervenor compensation must reimburse the fund
24for the amount of the grant. If the intervenor compensation
25amount is larger than the grant, then the balance shall be paid
26to the customer. If the amount of intervenor compensation is



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1less than the grant, then the customer must reimburse the
2Illinois Commerce Commission Intervenor Compensation Fund for
3the difference with payments made on a regular schedule within
45 years after the end of the proceeding.
5    (d) If a customer that receives a grant from the Illinois
6Commerce Commission Intervenor Compensation Fund does not
7subsequently prevail in receiving intervenor compensation,
8then the customer must reimburse the Illinois Commerce
9Commission Intervenor Compensation Fund for the amount of the
10grant with payments made on a regular schedule within 5 years
11of the end of the proceeding.
12    Section 50. Rulemaking. The Commission shall adopt any
13rules necessary to implement this Act. The Commission has the
14authority to initiate an emergency rulemaking to adopt rules
15regarding intervenor compensation if necessary to allow
16customer participation in dockets implementing new statutes.
17    Section 80. The Illinois Administrative Procedure Act is
18amended by adding Section 5-45.8 as follows:
19    (5 ILCS 100/5-45.8 new)
20    Sec. 5-45.8. Emergency rulemaking; Public Utilities
21Intervenor Compensation Act. To provide for the expeditious
22and timely implementation of the Public Utilities Intervenor
23Compensation Act, emergency rules may be adopted in accordance



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1with Section 5-45 by the Illinois Commerce Commission to
2implement the Public Utilities Intervenor Compensation Act.
3The adoption of emergency rules authorized by Section 5-45 and
4this Section is deemed to be necessary for the public
5interest, safety, and welfare.
6    This Section is repealed on January 1, 2027.
7    Section 85. The State Finance Act is amended by adding
8Section 5.935 as follows:
9    (30 ILCS 105/5.935 new)
10    Sec. 5.935. The Illinois Commerce Commission Intervenor
11Compensation Fund.
12    Section 90. The Public Utilities Act is amended by
13changing Sections 2-107, 9-220.3, 9-227, and 10-104 and by
14adding Sections 4-605, 16-105.17, 16-107.7, and 16-108.18 as
16    (220 ILCS 5/2-107)  (from Ch. 111 2/3, par. 2-107)
17    Sec. 2-107. The office of the Commission shall be in
18Springfield, but the Commission may, with the approval of the
19Governor, establish and maintain branch offices at places
20other than the seat of government. Such office shall be open
21for business between the hours of 8:30 a.m. and 5:00 p.m.
22throughout the year, and one or more responsible persons to be



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1designated by the executive director shall be on duty at all
2times in immediate charge thereof.
3    The Commission shall hold stated meetings at least once a
4month and may hold such special meetings as it may deem
5necessary at any place within the State. At each regular and
6special meeting that is open to the public, members of the
7public shall be afforded time, subject to reasonable
8constraints, to make comments to or to ask questions of the
9Commission. In any contested or rulemaking proceeding, at the
10request of any party or at least 5 members of the public, the
11Commission shall hold at least one public hearing, at a time
12and place accessible and convenient for affected customers to
13participate, where members of the public are invited to
14participate and present public comments in accordance with 2
15Ill. Adm. Code 1700.10. The hearing must take place at least 30
16days prior to the Commission's final order on the case.
17    The Commission shall provide a web site and a toll-free
18telephone number to accept comments from Illinois residents
19regarding any matter under the auspices of the Commission or
20before the Commission. The Commission staff shall report, in a
21manner established by the Commission that is consistent with
22the Commission's rules regarding ex parte communications, to
23the full Commission comments and suggestions received through
24both venues before all relevant votes of the Commission.
25    The Commission may, for the authentication of its records,
26process and proceedings, adopt, keep and use a common seal, of



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1which seal judicial notice shall be taken in all courts of this
2State; and any process, notice, order or other paper which the
3Commission may be authorized by law to issue shall be deemed
4sufficient if signed and certified by the Chairman of the
5Commission or his or her designee, either by hand or by
6facsimile, and with such seal attached; and all acts, orders,
7proceedings, rules, entries, minutes, schedules and records of
8the Commission, and all reports and documents filed with the
9Commission, may be proved in any court of this State by a copy
10thereof, certified to by the Chairman of the Commission, with
11the seal of the Commission attached.
12    Notwithstanding any other provision of this Section, the
13Commission's established procedures for accepting testimony
14from Illinois residents on matters pending before the
15Commission shall be consistent with the Commission's rules
16regarding ex parte communications and due process.
17(Source: P.A. 95-127, eff. 8-13-07.)
18    (220 ILCS 5/4-605 new)
19    Sec. 4-605. Restitution for misconduct.
20    (a) It is the policy of this State that public utility
21ethical and criminal misconduct shall not be tolerated. The
22General Assembly finds it necessary to collect restitution, to
23be distributed as described in subsection (d), from a public
24utility who has been found guilty of violations of criminal
25law or who has entered into a Deferred Prosecution Agreement



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1that details violations of criminal law.
2    (b) In light of such violations, the Illinois Commerce
3Commission shall, within 150 days after the effective date of
4this amendatory Act of the 102nd General Assembly, initiate an
5investigation into amounts necessary to be refunded to
6customers to restore funds to the State and to ratepayers that
7were collected by the electric public utility Commonwealth
8Edison Company as a result of ethical misconduct. The
9investigation shall conclude no later than 270 days following
10initiation, and shall be conducted as a contested proceeding.
11The investigation shall calculate benefits received by the
12public utility that were instituted as a result of illegal and
13unethical conduct, as set forth in the Deferred Prosecution
14Agreement of July 16, 2020 between the United States Attorney
15for the Northern District of Illinois and Commonwealth Edison
16Company, for passage of the Energy Infrastructure
17Modernization Act of 2011. The amount shall be no less than the
18total return on equity recovered for investments in
19infrastructure made pursuant to paragraph (1) of subsection
20(b) of Section 16-108.5 of this Act.
21    (c) Pursuant to subsection (d), the investigation shall
22calculate a schedule for remittance to state funds and to
23ratepayers, over a period of no more than 4 years, to be paid
24by the public utility from profits, returns, or shareholder
25dollars. No costs related to the investigation, restitution,
26or refunds may be recoverable through rates.



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1    (d) Funds collected pursuant to this Section shall be
2repaid by the public utility in the following manner:
3        (1) 25% shall be contributed to expand the Percentage
4    of Income Payment Program;
5        (2) the remaining percentage of funds collected shall
6    be provided as a per-kilowatt-hour credit to the public
7    utility's ratepayers.
8    (220 ILCS 5/9-220.3)
9    (Section scheduled to be repealed on December 31, 2023)
10    Sec. 9-220.3. Natural gas surcharges authorized.
11    (a) Tariff.
12        (1) Pursuant to Section 9-201 of this Act, a natural
13    gas utility serving more than 700,000 customers may file a
14    tariff for a surcharge which adjusts rates and charges to
15    provide for recovery of costs associated with investments
16    in qualifying infrastructure plant, independent of any
17    other matters related to the utility's revenue
18    requirement.
19        (2) Within 30 days after the effective date of this
20    amendatory Act of the 98th General Assembly, the
21    Commission shall adopt emergency rules to implement the
22    provisions of this amendatory Act of the 98th General
23    Assembly. The utility may file with the Commission tariffs
24    implementing the provisions of this amendatory Act of the
25    98th General Assembly after the effective date of the



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1    emergency rules authorized by subsection (i).
2        (3) The Commission shall issue an order approving, or
3    approving with modification to ensure compliance with this
4    Section, the tariff no later than 120 days after such
5    filing of the tariffs filed pursuant to this Section. The
6    utility shall have 7 days following the date of service of
7    the order to notify the Commission in writing whether it
8    will accept any modifications so identified in the order
9    or whether it has elected not to proceed with the tariff.
10    If the order includes no modifications or if the utility
11    notifies the Commission that it will accept such
12    modifications, the tariff shall take effect on the first
13    day of the calendar year in which the Commission issues
14    the order, subject to petitions for rehearing and
15    appellate procedures. After the tariff takes effect, the
16    utility may, upon 10 days' notice to the Commission, file
17    to withdraw the tariff at any time, and the Commission
18    shall approve such filing without suspension or hearing,
19    subject to a final reconciliation as provided in
20    subsection (e) of this Section.
21        (4) When a natural gas utility withdraws the surcharge
22    tariff, the utility shall not recover any additional
23    charges through the surcharge approved pursuant to this
24    Section, subject to the resolution of the final
25    reconciliation pursuant to subsection (e) of this Section.
26    The utility's qualifying infrastructure investment net of



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1    accumulated depreciation may be transferred to the natural
2    gas utility's rate base in the utility's next general rate
3    case. The utility's delivery base rates in effect upon
4    withdrawal of the surcharge tariff shall not be adjusted
5    at the time the surcharge tariff is withdrawn.
6        (5) A natural gas utility that is subject to its
7    delivery base rates being fixed at their current rates
8    pursuant to a Commission order entered in Docket No.
9    11-0046, notwithstanding the effective date of its tariff
10    authorized pursuant to this Section, shall reflect in a
11    tariff surcharge only those projects placed in service
12    after the fixed rate period of the merger agreement has
13    expired by its terms.
14    (b) For purposes of this Section, "qualifying
15infrastructure plant" includes only plant additions placed in
16service not reflected in the rate base used to establish the
17utility's delivery base rates. "Costs associated with
18investments in qualifying infrastructure plant" shall include
19a return on qualifying infrastructure plant and recovery of
20depreciation and amortization expense on qualifying
21infrastructure plant, net of the depreciation included in the
22utility's base rates on any plant retired in conjunction with
23the installation of the qualifying infrastructure plant.
24Collectively the "qualifying infrastructure plant" and "costs
25associated with investments in qualifying infrastructure
26plant" are referred to as the "qualifying infrastructure



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1investment" and that are related to one or more of the
3        (1) the installation of facilities to retire and
4    replace underground natural gas facilities, including
5    facilities appurtenant to facilities constructed of those
6    materials such as meters, regulators, and services, and
7    that are constructed of cast iron, wrought iron, ductile
8    iron, unprotected coated steel, unprotected bare steel,
9    mechanically coupled steel, copper, Cellulose Acetate
10    Butyrate (CAB) plastic, pre-1973 DuPont Aldyl "A"
11    polyethylene, PVC, or other types of materials identified
12    by a State or federal governmental agency as being prone
13    to leakage;
14        (2) the relocation of meters from inside customers'
15    facilities to outside;
16        (3) the upgrading of the gas distribution system from
17    a low pressure to a medium pressure system, including
18    installation of high-pressure facilities to support the
19    upgrade;
20        (4) modernization investments by a combination
21    utility, as defined in subsection (b) of Section 16-108.5
22    of this Act, to install:
23            (A) advanced gas meters in connection with the
24        installation of advanced electric meters pursuant to
25        Sections 16-108.5 and 16-108.6 of this Act; and
26            (B) the communications hardware and software and



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1        associated system software that creates a network
2        between advanced gas meters and utility business
3        systems and allows the collection and distribution of
4        gas-related information to customers and other parties
5        in addition to providing information to the utility
6        itself;
7        (5) replacing high-pressure transmission pipelines and
8    associated facilities identified as having a higher risk
9    of leakage or failure or installing or replacing
10    high-pressure transmission pipelines and associated
11    facilities to establish records and maximum allowable
12    operating pressures;
13        (6) replacing difficult to locate mains and service
14    pipes and associated facilities; and
15        (7) replacing or installing transmission and
16    distribution regulator stations, regulators, valves, and
17    associated facilities to establish over-pressure
18    protection.
19    With respect to the installation of the facilities
20identified in paragraph (1) of subsection (b) of this Section,
21the natural gas utility shall determine priorities for such
22installation with consideration of projects either: (i)
23integral to a general government public facilities improvement
24program or (ii) ranked in the highest risk categories in the
25utility's most recent Distribution Integrity Management Plan
26where removal or replacement is the remedial measure.



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1    (c) Qualifying infrastructure investment, defined in
2subsection (b) of this Section, recoverable through a tariff
3authorized by subsection (a) of this Section, shall not
4include costs or expenses incurred in the ordinary course of
5business for the ongoing or routine operations of the utility,
6including, but not limited to:
7        (1) operating and maintenance costs; and
8        (2) costs of facilities that are revenue-producing,
9    which means facilities that are constructed or installed
10    for the purpose of serving new customers.
11    (d) Gas utility commitments. A natural gas utility that
12has in effect a natural gas surcharge tariff pursuant to this
13Section shall:
14        (1) recognize that the General Assembly identifies
15    improved public safety and reliability of natural gas
16    facilities as the cornerstone upon which this Section is
17    designed, and qualifying projects should be encouraged,
18    selected, and prioritized based on these factors; and
19        (2) provide information to the Commission as requested
20    to demonstrate that (i) the projects included in the
21    tariff are indeed qualifying projects and (ii) the
22    projects are selected and prioritized taking into account
23    improved public safety and reliability.
24        (3) The amount of qualifying infrastructure investment
25    eligible for recovery under the tariff in the applicable
26    calendar year is limited to the lesser of (i) the actual



SB2295- 23 -LRB102 17361 SPS 22854 b

1    qualifying infrastructure plant placed in service in the
2    applicable calendar year and (ii) the difference by which
3    total plant additions in the applicable calendar year
4    exceed the baseline amount, and subject to the limitation
5    in subsection (g) of this Section. A natural gas utility
6    can recover the costs of qualifying infrastructure
7    investments through an approved surcharge tariff from the
8    beginning of each calendar year subject to the
9    reconciliation initiated under paragraph (2) of subsection
10    (e) of this Section, during which the Commission may make
11    adjustments to ensure that the limits defined in this
12    paragraph are not exceeded. Further, if total plant
13    additions in a calendar year do not exceed the baseline
14    amount in the applicable calendar year, the Commission,
15    during the reconciliation initiated under paragraph (2) of
16    subsection (e) of this Section for the applicable calendar
17    year, shall adjust the amount of qualifying infrastructure
18    investment eligible for recovery under the tariff to zero.
19        (4) For purposes of this Section, "baseline amount"
20    means an amount equal to the utility's average of total
21    depreciation expense, as reported on page 336, column (b)
22    of the utility's ILCC Form 21, for the calendar years 2006
23    through 2010.
24    (e) Review of investment.
25        (1) The amount of qualifying infrastructure investment
26    shall be shown on an Information Sheet supplemental to the



SB2295- 24 -LRB102 17361 SPS 22854 b

1    surcharge tariff and filed with the Commission monthly or
2    some other time period at the option of the utility. The
3    Information Sheet shall be accompanied by data showing the
4    calculation of the qualifying infrastructure investment
5    adjustment. Unless otherwise ordered by the Commission,
6    each qualifying infrastructure investment adjustment shown
7    on an Information Sheet shall become effective pursuant to
8    the utility's approved tariffs.
9        (2) For each calendar year in which a surcharge tariff
10    is in effect, the natural gas utility shall file a
11    petition with the Commission to initiate hearings to
12    reconcile amounts billed under each surcharge authorized
13    pursuant to this Section with the actual prudently
14    incurred costs recoverable under this tariff in the
15    preceding year. The petition filed by the natural gas
16    utility shall include testimony and schedules that support
17    the accuracy and the prudence of the qualifying
18    infrastructure investment for the calendar year being
19    reconciled. The petition filed shall also include the
20    number of jobs attributable to the natural gas surcharge
21    tariff as required by rule. The review of the utility's
22    investment shall include identification and review of all
23    plant that was ranked within the highest risk categories
24    in that utility's most recent Distribution Integrity
25    Management Plan.
26    (f) The rate of return applied shall be the overall rate of



SB2295- 25 -LRB102 17361 SPS 22854 b

1return authorized by the Commission in the utility's last gas
2rate case.
3    (g) The cumulative amount of increases billed under the
4surcharge, since the utility's most recent delivery service
5rate order, shall not exceed an annual average 4% of the
6utility's delivery base rate revenues, but shall not exceed
75.5% in any given year. On the effective date of new delivery
8base rates, the surcharge shall be reduced to zero with
9respect to qualifying infrastructure investment that is
10transferred to the rate base used to establish the utility's
11delivery base rates, provided that the utility may continue to
12charge or refund any reconciliation adjustment determined
13pursuant to subsection (e) of this Section.
14    (h) If a gas utility obtains a surcharge tariff under this
15Section 9-220.3, then it and its affiliates are excused from
16the rate case filing requirements contained in Sections
179-220(h) and 9-220(h-1). In the event a natural gas utility,
18prior to the effective date of this amendatory Act of the 98th
19General Assembly, made a rate case filing that is still
20pending on the effective date of this amendatory Act of the
2198th General Assembly, the natural gas utility may, at the
22time it files its surcharge tariff with the Commission, also
23file a notice with the Commission to withdraw its rate case
24filing. Any affiliate of such natural gas utility may also
25file to withdraw its rate case filing. Upon receipt of such
26notice, the Commission shall dismiss the rate case filing with



SB2295- 26 -LRB102 17361 SPS 22854 b

1prejudice and such tariffs and the record related thereto
2shall not be the subject of any further hearing,
3investigation, or proceeding of any kind related to rates for
4gas delivery services. Notwithstanding the foregoing, a
5natural gas utility shall not be permitted to withdraw a rate
6case filing for which a proposed order recommending a rate
7reduction is pending. A natural gas utility shall not be
8permitted to withdraw the gas delivery services tariffs that
9are the subject of Commission Docket Nos. 12-0511/12-0512
10(cons.). None of the costs incurred for the withdrawn rate
11case are recoverable from ratepayers.
12    (i) The Commission shall promulgate rules and regulations
13to carry out the provisions of this Section under the
14emergency rulemaking provisions set forth in Section 5-45 of
15the Illinois Administrative Procedure Act, and such emergency
16rules shall be effective no later than 30 days after the
17effective date of this amendatory Act of the 98th General
19    (j) Utilities that have elected to recover qualifying
20infrastructure investment costs pursuant to this Section shall
21file annually their Distribution Integrity Management Plan
22(DIMP) with the Commission no later than June 1 of each year
23the utility has said tariff in effect. The DIMP shall include
24the following information:
25        (1) Baseline Distribution System Data: Information
26    such as demand, system pressures and flows, and metering



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1    infrastructure.
2        (2) Financial Data: historical and projected spending
3    on distribution system infrastructure.
4        (3) Scenario Analysis: Discussion of projected changes
5    in usage over time.
6        (4) Descriptions of all qualifying infrastructure
7    investment proposed for the coming year.
8    (k) Within 45 days after filing, the Commission shall,
9with reasonable notice, open an investigation to consider
10whether the Plan meets the objectives set forth in this
11subsection and contains the information required by subsection
12(j). The Commission shall issue a final order approving the
13Plan, with any modifications the Commission deems reasonable
14and appropriate to achieve the goals of this Section, within
15270 days after the Plan filing. The investigation shall assess
16whether the DIMP:
17        (1) ensures optimized use of utility infrastructure
18    assets and resources to minimize total system costs;
19        (2) enables greater customer engagement, empowerment,
20    and options for services;
21        (3) to the maximum extent possible, achieves and or
22    supports the achievement of greenhouse gas emissions
23    reductions as described by Section 9.10 of the
24    Environmental Protection Act; and
25        (4) supports existing Illinois policy goals promoting
26    energy efficiency.



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1    The Commission process shall maximize the sharing of
2information, ensure robust stakeholder participation, and
3recognize the responsibility of the utility to ultimately
4manage the grid in a safe, reliable manner.
5    (l) (j) This Section is repealed December 31, 2023.
6(Source: P.A. 98-57, eff. 7-5-13.)
7    (220 ILCS 5/9-227)  (from Ch. 111 2/3, par. 9-227)
8    Sec. 9-227. It is the policy of this State to encourage
9electric and natural gas public utilities to promote the
10welfare of this State and their communities through donations
11made from the utility's shareholder profits rather than by
12using ratepayer funds. Such contributions shall not be
13recoverable through the public utility's rates. It shall be
14proper for the Commission to consider as an operating expense,
15for the purpose of determining whether a rate or other charge
16or classification is sufficient, donations made by a public
17utility for the public welfare or for charitable scientific,
18religious or educational purposes, provided that such
19donations are reasonable in amount. In determining the
20reasonableness of such donations, the Commission may not
21establish, by rule, a presumption that any particular portion
22of an otherwise reasonable amount may not be considered as an
23operating expense. The Commission shall be prohibited from
24disallowing by rule, as an operating expense, any portion of a
25reasonable donation for public welfare or charitable purposes.



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1(Source: P.A. 85-122.)
2    (220 ILCS 5/10-104)  (from Ch. 111 2/3, par. 10-104)
3    Sec. 10-104. Public hearings.
4    (a) As used in this Section, "major case" includes:
5        (1) rate cases;
6        (2) rulemakings;
7        (3) other proceedings with a significant effect on
8    rates;
9        (4) large infrastructure projects with significant
10    nonrate impacts on communities near their location;
11        (5) new programs;
12        (6) any planning dockets related to energy efficiency,
13    renewable energy, and interconnection infrastructure; and
14        (7) any other docketed or undocketed proceedings for
15    which the Commission feels that robust public engagement
16    is needed.
17    (b) When the outcome of a major case would have effects
18statewide, or have any significant effects outside the
19territory of the utility or utilities involved in the case,
20the Commission shall hold at least 5 public hearings for the
21purpose of receiving public comment on each such major case.
22One of these hearings must be in the Chicago metropolitan
23area. One of these hearings must be in Springfield. The
24remaining 3 hearings must be outside of the Chicago
25metropolitan area and Springfield. One of the hearings shall



SB2295- 30 -LRB102 17361 SPS 22854 b

1be held within the county in which the subject matter of the
2hearing is situated, if it is situated within one county. When
3the outcome of a major case would have effects only within the
4territory of one utility, the Commission shall hold at least 5
5public hearings at a variety of geographic locations within
6the utility's territory. The locations shall be chosen to give
7a wide variety of stakeholders the best opportunity to
8participate in the hearings. The Commission may combine public
9hearings for multiple major cases into one event at a single
10venue, where practicable and compliant with all other
12    (c) The public hearings shall be held at times that make
13them accessible to the public, including to residents who work
14during the day. The public hearings shall be held at locations
15easily accessible, whenever possible, by public
16transportation. The public hearings shall be held at locations
17with wheelchair access. Upon request, a sign language
18interpreter or other equivalent assistance for the hearing
19impaired shall be provided. Upon request, translation services
20shall be provided. Translation services may include real-time
21telephone-based or other real-time translation services. All
22written materials distributed at public hearings by the
23Commission or utilities must be available at the hearing in
24Spanish and, upon request and reasonable notice, other
25languages. Call-in options shall be provided.
26    (d) At least 3 commissioners shall attend each public



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1hearing in person.
2    (e) Public hearings under this Section are subject to the
3Open Meetings Act.
4    (f) The Commission may collect a reasonable fee from the
5affected utility to offset the cost of public hearings,
6including the cost of staffing. Within 30 days after the
7effective date of this amendatory Act of the 102nd General
8Assembly, the Commission shall set the amount of the fee and
9shall update the amount of the fee no less often than every 3
10years thereafter. All fees charged and collected by the
11Commission shall be paid promptly after the receipt of the
12same, accompanied by a detailed statement thereof, into the
13Public Utility Fund in the State treasury. All hearings before
14the Commission or any commissioner or administrative law judge
15shall be held within the county in which the subject matter of
16the hearing is situated, or if the subject matter of the
17hearing is situated in more than one county, then at a place or
18places designated by the Commission, or agreed upon by the
19parties in interest, within one or more such counties, or at
20the place which in the judgment of the Commission shall be most
21convenient to the parties to be heard.
22(Source: P.A. 100-840, eff. 8-13-18.)
23    (220 ILCS 5/16-105.17 new)
24    Sec. 16-105.17. Multi-Year Integrated Grid Plan.
25    (a) Findings and Purpose. The General Assembly finds that



SB2295- 32 -LRB102 17361 SPS 22854 b

1better aligning regulated utility operations, expenditures and
2investments with public benefit goals including safety;
3reliability; efficiency; affordability; equity; emissions
4reductions; and expansion of clean distributed energy
5resources, is critical to ensuring that Illinois residents and
6businesses do not suffer economic and environmental harm from
7the State's energy systems and to maximize the potential
8benefits from utility expenditures. To that end, it is the
9policy of the State of Illinois to promote inclusive,
10comprehensive, transparent, cost-effective distribution
11system planning that minimizes long-term costs for Illinois
12customers and supports the achievement of state renewable
13energy development and other clean energy, public health, and
14environmental policy goals. Utility distribution system
15expenditures, programs, investments and policies must be
16evaluated in coordination with these goals. In particular, the
17General Assembly finds that:
18        (1) Illinois' electricity distribution system must
19    cost-effectively integrate renewable energy resources,
20    including utility-scale renewable energy resources,
21    community renewable generation and distributed renewable
22    energy resources, support beneficial electrification
23    including electric vehicle use and adoption, promote
24    opportunities for third-party investment in
25    nontraditional, grid-related technologies and resources
26    such as batteries, solar photovoltaic panels and smart



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1    thermostats, reduce energy usage generally and especially
2    during times of greatest reliance on fossil fuels, and
3    enhance customer engagement opportunities.
4        (2) Inclusive distribution system planning is an
5    essential tool for the Illinois Commerce Commission,
6    public utilities, and stakeholders to effectively
7    coordinate environmental, consumer, reliability and equity
8    goals at fair and reasonable costs, and for ensuring
9    transparent utility accountability for meeting those
10    goals.
11        (3) Any planning process should advance Illinois
12    energy policy goals while ensuring utility investments are
13    cost-effective. Such a process should maximize the sharing
14    of information, ensure robust stakeholder participation,
15    and recognize the responsibility of the utility to
16    ultimately manage the grid in a safe, reliable manner.
17        (4) Since the passage of the Energy Infrastructure
18    Modernization Act in 2011, Illinois consumers have
19    invested billions of dollars toward electric utility grid
20    modernization. In the absence of a transparent
21    distribution planning process, however, those investments
22    have not served customers' best interests, have failed to
23    promote the expansion of clean distributed energy
24    resources, and have failed to advance equity and
25    environmental justice.
26        (5) The traditional regulatory model rewards utilities



SB2295- 34 -LRB102 17361 SPS 22854 b

1    for increasing capital expenditures by basing allowed
2    revenues on the value of the rate base, resulting in an
3    incentive for ever-increasing capital investments. The
4    General Assembly is concerned that the existing regulatory
5    model does not align the interests of customers, the
6    State, and utilities because it does not encourage
7    utilities to systematically analyze and consider
8    nontraditional solutions to utility, customer and grid
9    needs that may be more efficient and cost effective, and
10    less environmentally harmful than traditional solutions.
11    Nontraditional solutions include distributed energy
12    resources owned or implemented by customers and
13    independent third parties, controllable load, beneficial
14    electrification, or rate design that rewards efficient
15    energy use, for example.
16        (6) The General Assembly also finds that Illinois
17    utilities' current processes for planning their
18    distribution system are not reasonably accessible or
19    transparent to individuals and communities who pay for and
20    are affected by the utilities' distribution system assets,
21    and that more inclusive and accessible distribution system
22    planning processes would be in the interests of all
23    Illinois residents, but especially those residents
24    historically most negatively impacted by unsafe or
25    environmentally harmful energy infrastructure.
26        (7) The General Assembly finds it would be beneficial



SB2295- 35 -LRB102 17361 SPS 22854 b

1    to require utilities to demonstrate how their spending
2    promotes identified state energy goals, such as
3    integrating renewable energy; empowering customers;
4    supporting electric vehicles, beneficial electrification
5    and energy storage; achieving equity goals; and
6    maintaining reliability.
7    The General Assembly therefore directs the utilities to
8implement distribution system planning in order to accelerate
9progress on Illinois clean energy and environmental goals and
10hold electric utilities publicly accountable for their
12    (b) Definitions. As used in this Section:
13    "Commission" means the Illinois Commerce Commission.
14    "Demand response" means measures that decrease peak
15electricity demand or shift demand from peak to off-peak
17    "Distributed energy resources" or "DER" means a wide range
18of technologies that are located on the customer side of the
19customer's electric meter and can provide value to the
20distribution system, including, but not limited to,
21distributed generation, energy storage, electric vehicles, and
22demand response technologies.
23    "Environmental justice communities" means the definition
24of that term based on existing methodologies and findings,
25used and as may be updated by the Illinois Power Agency and its
26Program Administrator in the Illinois Solar for All Program.



SB2295- 36 -LRB102 17361 SPS 22854 b

1    (c) Application. This Section applies to electric
2utilities serving more than 500,000 retail customers in the
4    (d) Objectives. The Multi-Year Integrated Grid Plan ("the
5Plan") shall be designed to:
6        (1) ensure coordination of the State's renewable
7    energy goals, climate and environmental goals, utility
8    distribution system investments, and programs, policies
9    and investments described in this Section to maximize the
10    benefits of each while ensuring utility expenditures are
11    cost-effective;
12        (2) bring the benefits of grid modernization and clean
13    energy, including, but not limited to, deployment of
14    distributed energy resources, to ratepayers in
15    economically disadvantaged and environmental justice
16    communities throughout Illinois, with at least 40% of
17    these benefits being allocated to these ratepayers;
18        (3) enable greater customer engagement, empowerment,
19    and options for energy services;
20        (4) reduce grid congestion, minimize the time and
21    expense associated with interconnection, and increase the
22    capacity of the distribution grid to host increasing
23    levels of distributed energy resources, to facilitate
24    availability and development of distributed energy
25    resources, particularly in locations that enhance consumer
26    and environmental benefits;



SB2295- 37 -LRB102 17361 SPS 22854 b

1        (5) ensure opportunities for robust public
2    participation through open, transparent planning
3    processes;
4        (6) provide for the analysis of the cost-effectiveness
5    of proposed system investments, which takes into account
6    environmental costs and benefits;
7        (7) to the maximum extent possible, achieve or support
8    the achievement of Illinois environmental goals, including
9    those described in Section 9.10 of the Environmental
10    Protection Act, Section 1-75 of the Illinois Power Agency
11    Act, and emissions reductions required to improve the
12    health, safety and prosperity of all Illinois residents;
13        (8) support existing Illinois policy goals promoting
14    distributed energy resources and investments in renewable
15    energy resources; and
16        (9) provide sufficient public information to the
17    Commission, stakeholders, and market participants in order
18    to enable nonemitting customer-owned or third-party
19    distributed energy resources, acting individually or in
20    aggregate, to seamlessly and easily connect to the grid;
21    provide grid benefits; support grid services; and achieve
22    environmental outcomes, without necessarily requiring
23    utility ownership or unreasonable control over those
24    resources, and enable those resources to act as
25    alternatives to utility capital investments.
26    (e) Plan Development Stakeholder Process. No later than



SB2295- 38 -LRB102 17361 SPS 22854 b

1February 1, 2022, the Illinois Commerce Commission shall
2initiate a series of no fewer than 6 workshops which shall
3inform the filing requirements for, and contents of, the
4Multi-Year Integrated Grid Plans to be filed by electric
5utilities subject to this Section. The series of workshops
6shall be 11 months in length, concluding no later than
7December 31, 2022. The workshops shall be facilitated by an
8independent third-party facilitator selected by Staff of the
9Illinois Commerce Commission and approved by the Executive
10Director of the Illinois Commerce Commission.
11        (1) The workshops shall be designed to achieve the
12    following objectives:
13            (i) review utilities' past, current and planned
14        capital investments and all supporting data;
15            (ii) review utilities' historic and projected
16        load;
17            (iii) review how utilities plan to invest in their
18        distribution system in order to meet the system's
19        projected needs;
20            (iv) review locational data on reliability,
21        service quality, program participation and investment,
22        provided by the utilities;
23            (v) integrate input from diverse stakeholders,
24        including representatives from environmental justice
25        communities, geographically diverse communities,
26        low-income representatives, consumer representatives,



SB2295- 39 -LRB102 17361 SPS 22854 b

1        environmental representatives, organized labor
2        representatives, third-party technology providers, and
3        utilities;
4            (vi) consider proposals from utilities and
5        stakeholders on programs and policies necessary to
6        achieve the objectives in subsection (d) of this
7        Section; and
8            (vii) develop detailed filing requirements
9        applicable to each component of the utilities'
10        Multi-Year Integrated Grid Plan filings under
11        paragraph (2) of subsection (f) of this Section.
12        (2) To the extent any of the information in
13    subparagraphs (i) through (iv) of paragraph (1) of this
14    subsection is designated as confidential because
15    disclosure of such threatens the security of critical
16    system infrastructure, that information shall be redacted
17    as necessary but made available to parties who agree in
18    writing to abide by confidentiality agreements as approved
19    by the Office of General Counsel of the Illinois Commerce
20    Commission. Information appropriately designated as
21    confidential shall only include that which is critical to
22    system security, and shall not include that information in
23    which the electric utility claims a proprietary business
24    interest.
25        (3) Workshops should be organized and facilitated in a
26    manner that encourages representation from diverse



SB2295- 40 -LRB102 17361 SPS 22854 b

1    stakeholders, ensuring equitable opportunities for
2    participation, without requiring formal intervention or
3    representation by an attorney. Workshops should be held
4    during both day and evening hours, in a variety of
5    locations around the State, and should allow remote
6    participation.
7        (4) Utilities shall provide system data, including
8    data described in subparagraphs (i) through (iv) of
9    paragraph (1) of subsection (e), at a time prior to the
10    start of workshops to allow interested stakeholders to
11    reasonably review data before attending workshops. To
12    facilitate public feedback, the administrator facilitating
13    the workshops shall, throughout the workshop process,
14    develop questions for stakeholder input on topics being
15    considered. This may include, but is not limited to:
16    design of the workshop process, locational data and
17    information provided by utilities, alignment of plans,
18    programs, investments and objectives, and other topics as
19    deemed appropriate by the Commission facilitation staff.
20    Stakeholder feedback shall not be limited to these
21    questions.
22        (5) Workshops shall not be considered settlement
23    negotiations, compromise negotiations, or offers to
24    compromise for the purposes of Illinois Rule of Evidence
25    408. All materials shared as a part of the workshop
26    process shall be made publicly available on a website made



SB2295- 41 -LRB102 17361 SPS 22854 b

1    available by the Commission.
2        (6) On conclusion of the workshops, the Commission
3    shall open a comment period that allows interested and
4    diverse stakeholders to submit comments and
5    recommendations regarding the utilities' Multi-Year
6    Integrated Grid Plan filings. Based on the workshop
7    process and stakeholder comments and recommendations
8    offered verbally or in writing during the workshops and in
9    writing during the comment period following the workshops,
10    the independent third-party facilitator shall prepare a
11    report, to be submitted to the Commission no later than
12    February 1, 2022, describing the stakeholders,
13    discussions, proposals, and areas of consensus and
14    disagreement from the workshop process, and making
15    recommendations to the Commission regarding the utilities'
16    Multi-Year Integrated Grid Plan filings. Interested
17    stakeholders shall have an opportunity to provide comment
18    on the independent third-party facilitator Report.
19        (7) Based on discussions in the workshops, the Staff
20    Report, and stakeholder comments and recommendations made
21    during and following the workshop process, the Commission
22    shall issue Initiating Orders no later than April 1, 2022,
23    requiring the electric utilities subject to this Section
24    to file the first Multi-Year Integrated Grid Plan no later
25    than June 1, 2022. The Initiating Orders shall specify the
26    requirements applicable to the utilities' Multi-Year



SB2295- 42 -LRB102 17361 SPS 22854 b

1    Integrated Grid Plans, above and beyond any requirements
2    described in paragraph (2) of subsection (f) of this
3    Section, and shall:
4            (i) analyze and identify specific programs,
5        policies, and initiatives, among those that were
6        raised during the workshop process, that the utilities
7        must implement as a part of their Multi-Year
8        Integrated Grid Plans; and
9            (ii) specify types of analyses and calculations
10        the utilities shall perform, as well as scenarios they
11        must analyze and (where applicable) specific
12        assumptions they must use in the development of their
13        Multi-Year Integrated Grid Plans.
14    (f) Multi-Year Integrated Grid Plan.
15        (1) Design Objectives. Pursuant to this subsection (f)
16    of this Section 1and the Initiating Orders of the
17    Commission, to be filed no later than April 1, 2022, and
18    for each subsequent Plan thereafter, each electric utility
19    subject to this Section shall, no later than June 1, 2022,
20    submit its first Multi-Year Integrated Grid Plan. While
21    each Multi-Year Integrated Grid Plan will include a
22    long-term, ten-year planning horizon, the Initial Plan
23    shall be in effect from June 1, 2023 through May 31, 2026.
24    Each Plan shall:
25            (i) incorporate requirements established by the
26        Commission in its Initiating Order; and



SB2295- 43 -LRB102 17361 SPS 22854 b

1            (ii) Propose programs, policies and plans designed
2        to optimize achievement of the objectives set forth in
3        subsection (d) of this Section.
4        To the extent practicable and reasonable, all
5    programs, policies and initiatives proposed by the utility
6    in its plan should be informed by stakeholder input
7    received during the workshop process pursuant to
8    subsection (e) of this Section. Where specific stakeholder
9    input has not been incorporated in proposed programs,
10    policies, and plans, the electric utility shall provide an
11    explanation as to why that input was not incorporated.
12        (2) Plan Components. In order to ensure electric
13    utilities' ability to meet the goals and objectives set
14    forth in this Section, the Multi-Year Integrated Grid
15    Plans must include, at minimum, the following information:
16            (i) Baseline Distribution System Data. A detailed
17        description of the current operating conditions for
18        the distribution system, including a detailed
19        description, with supporting data, of: system
20        conditions, including asset age and useful life,
21        ratings, loadings, and other characteristics, as well
22        as:
23                (A) modeling software currently used and
24            planned software deployments;
25                (B) the distribution system annual loss
26            percentage for the prior year (average of 12



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1            monthly loss percentages);
2                (C) the maximum hourly coincident load (kW)
3            for the distribution system as measured at the
4            interface between the transmission and
5            distribution system;
6                (D) total distribution substation capacity in
7            kVa;
8                (E) total distribution transformer capacity in
9            kVa;
10                (F) total miles of overhead distribution wire;
11                (G) total miles of underground distribution
12            wire;
13                (H) current and expected reliability measures;
14                (I) detailed listing of all high-voltage and
15            low-voltage substations and circuits including, at
16            minimum, the following for each substation and
17            circuit: age, remaining useful life, capacity
18            rating, historical peak demand, historical
19            interval data, historic annual peak load growth,
20            forecast future annual peak load growth,
21            historical outages and voltage violations,
22            distribution system reliability events,
23            anticipated or modeled violations, existing and
24            planned visibility and measurement (feeder-level
25            and time) data, monitoring and control
26            capabilities, daytime minimum load, and other



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1            characteristics as necessary to allow the
2            Commission and stakeholders to analyze system data
3            for the purposes of achieving the goals of this
4            Section;
5                (J) distributed energy resource deployment by
6            type, size, customer class, and geographic
7            dispersion; and
8                (K) total number and nameplate capacity of
9            distributed energy resources that completed
10            interconnection to the system in each of the prior
11            5 years, including average time to process
12            interconnection applications for each type of
13            resource and interconnection level.
14            (ii) Distribution System Planning Process. A
15        detailed description of the electric utility's
16        distribution system planning process including, but
17        not limited to: any process required by a regional
18        transmission organization; forecasts, inputs and
19        assumptions of future total load and future peak
20        demand; planned infrastructure investments and
21        underlying assumptions regarding the necessity of such
22        investments; and other relevant details for the
23        10-year planning horizon.
24            (iii) Hosting Capacity and Interconnection
25        Analysis. A hosting capacity analysis which includes a
26        detailed and current analysis of how much capacity is



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1        available on each substation, circuit and node for
2        integrating renewable and distributed energy resources
3        as allowed by thermal ratings, protection system
4        limits, power quality standards, and safety standards.
5        This section must include: circuit-level maps and
6        downloadable data sets for public use; an assessment
7        of how anticipated investments (for as far into the
8        future as the utility has planned investments) will
9        impact the analysis; and a narrative discussion of how
10        the hosting capacity analysis advances customer-sited
11        distributed energy resources, including in particular
12        electric vehicles, electric storage systems and
13        photovoltaic resources.
14            (iv) Scenario Analysis and Load Forecasting.
15        Detailed load forecasts for the following 10 years at
16        the substation and circuit level, using dynamic load
17        forecasting (forecasting using multiple scenarios and
18        probabilistic planning) and accounting for the impacts
19        of anticipated energy efficiency programs, demand
20        response programs, distributed energy resources,
21        electric vehicle adoption, and other known or
22        anticipated variables. This section shall also include
23        a detailed description of the electric utility's
24        anticipated capacity, thermal, voltage or other grid
25        constraints for the following 3-year period, including
26        modifications or upgrades to the system required to



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1        accommodate anticipated future load and distributed
2        energy resource adoption. This section shall also
3        include a discussion of the development of base-case,
4        medium and high scenarios of distributed energy
5        resource deployment, reflecting a reasonable mix of
6        individual distributed energy resource adoption and
7        aggregated or bundled distributed energy resource
8        service types, and detailed information on the
9        methodologies used to develop those scenarios.
10            (v) Grid Value Analysis. An evaluation of the
11        short- and long-run benefits and costs of distributed
12        energy resources located on the distribution system,
13        including, but not limited to, the locational,
14        temporal, and performance-based benefits and costs of
15        distributed energy resources. This evaluation shall be
16        based on the reductions or increases in local
17        generation capacity needs, avoided or increased
18        investments in distribution infrastructure, avoided or
19        increased line-losses, voltage support and ancillary
20        services, safety benefits, reliability benefits,
21        resilience benefits, and any other savings, benefits
22        or value the distributed energy resources individually
23        or in aggregate provide to the distribution system or
24        costs to ratepayers of the electric utility. The
25        utility shall use the results of this evaluation to
26        inform its analysis of Solution Sourcing



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1        Opportunities, including nonwires alternatives, under
2        subparagraph (viii) of this paragraph (2). The
3        Commission may use the data produced through this
4        evaluation to, among other use-cases, establish
5        tariffs and compensation for distributed energy
6        resources interconnecting to the utility's
7        distribution system, including rebates provided by the
8        electric utility pursuant to Section 16-107.6 of this
9        Act.
10            (vi) Utility System Investment Plan. A detailed
11        description of historic distribution system capital
12        investments for the preceding 5 years and planned
13        capital investments for the following 10 years, as
14        well as load forecasts and all other data supporting
15        those investments. This section shall include
16        projected costs, scope of work, prioritization of
17        work, sequencing of investments, and explanations of
18        how planned investments will meet the objectives
19        described in subsection (d).
20            (vii) Utility Operations Plan. A detailed
21        description of historic distribution system operations
22        and maintenance expenditures for the preceding 5 years
23        and of planned operations and maintenance expenditures
24        for the following 10 years, as well as the data,
25        reasoning and explanation supporting planned
26        expenditures. This section shall also include a



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1        description of total costs spent on distributed energy
2        resource interconnection review and commissioning
3        (including application review, responding to
4        inquiries, metering, testing and other costs), as well
5        as interconnection fees and charges to customers and
6        installers of distributed energy resources, including
7        (application, metering and make-ready fees), broken
8        down by type of generation and category or level of
9        interconnection review, over each of the preceding 5
10        years.
11            (viii) Solution Sourcing Opportunities.
12        Identification of potential cost-effective solutions
13        from nontraditional and third-party owned investments
14        that could meet anticipated grid needs, including, but
15        not limited to: distributed energy resource
16        procurements, tariffs or contracts, programmatic
17        solutions, rate design options, technologies or
18        programs that facilitate load flexibility, nonwires
19        alternatives, and other solutions that are intended to
20        meet the objectives described at subsection (d). It is
21        the policy of this State that cost-effective
22        third-party or customer-owned distributed energy
23        resources shall be prioritized because those resources
24        create robust competition and customer choice.
25            (ix) Interoperability Plan. A detailed description
26        of the utility's interoperability plan, which must



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1        describe the manner in which the electric utility's
2        current and planned distribution system investments
3        will work together and exchange information and data,
4        the extent to which the utility is implementing open
5        standards and interfaces with third-party distributed
6        energy resource owners and aggregators, and the
7        utility's plan for interoperability testing and
8        certification.
9            (x) Flexibility Analysis. A detailed analysis of
10        current and projected flexible resources, including
11        resource type, size (in MW and MWh), location and
12        environmental impact, as well as anticipated needs
13        that can be met using flexible resources (including,
14        but not limited to, peak load reduction, managing ramp
15        needs, storing excess generation, and avoiding
16        unnecessary transmission expenditures).
17            (xi) Equity Requirements. A description of,
18        exclusive of low-income rate relief programs and other
19        income-qualified programs, how the utility is ensuring
20        that at least 40% of benefits from programs, policies,
21        and initiatives proposed in their Multi-Year
22        Integrated Grid Plan will be directed to ratepayers in
23        low-income and environmental justice communities. This
24        should include locational reporting, at the
25        census-tract level, on distribution system
26        investments, program participation, and reliability



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1        and service quality data.
2        (3) To the extent any information in utilities'
3    Multi-Year Integrated Grid Plans is designated as
4    confidential because disclosure of such threatens the
5    security of critical system infrastructure, that
6    information shall be redacted as necessary but made
7    available to parties who agree in writing to abide by
8    confidentiality requirements as approved by the Office of
9    General Counsel of the Illinois Commerce Commission.
10    Information appropriately designated as confidential shall
11    only include that which is critical to system security,
12    and shall not include that information in which the
13    electric utility claims only a proprietary business
14    interest.
15        (4) Comprehensive Consideration of Related Plans,
16    Tariffs, Programs and Policies. It is the policy of this
17    State that holistic consideration of all related
18    investments, planning processes, tariffs, rate design
19    options, programs, and other utility policies and plans
20    shall be required. To that end, the Commission shall
21    consider, comprehensively, the impact of all related
22    plans, tariffs, programs and policies on the Plan and on
23    each other, including:
24            (i) time-of-use pricing program, pursuant to
25        Section 16-107.7 of this Act, hourly pricing program,
26        pursuant to Section 16-107 of this Act, and any other



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1        time-variant or dynamic pricing program;
2            (ii) distributed generation rebate, pursuant to
3        Section 16-107.6 of this Act;
4            (iii) net electricity metering, pursuant to
5        Section 16-107.5 of this Act;
6            (iv) energy efficiency programs, pursuant to
7        Section 8-103B of this Act;
8            (v) Electric Vehicle Access for All programs,
9        pursuant to Section 30 of the Electric Vehicle Act;
10            (vi) beneficial electrification programs, pursuant
11        to Section 16-107.8 of this Act;
12            (vii) other plans, programs and policies that are
13        relevant to distribution grid investments, costs
14        planning, etc.
15        The Plan shall comprehensively detail the relationship
16    between these plans, tariffs, and programs and the Plan
17    and to the electric utility's achievement of the
18    objectives in subsection (d). The Plan shall be designed
19    to coordinate each of these plans, programs and tariffs
20    with the electric utility's long-term distribution system
21    investment planning in order to maximize the benefits of
22    each.
23        (5) Hearing Procedure. The Initiating Order for the
24    Initial Multi-Year Integrated Grid Plan, as well as each
25    electric utility's subsequent Integrated Grid Plans under
26    subsection (g), shall begin a contested proceeding as



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1    described in subsection (d) of Section 10-101.1 of this
2    Act.
3            (i) In evaluating a utility's Plan, the Commission
4        shall consider, at minimum, whether the Plan:
5                (A) meets the objectives of this Section;
6                (B) includes the components in paragraph (2)
7            of subsection (f) of this Section;
8                (C) incorporates input from interested
9            stakeholders, including parties and people who
10            offer public comment;
11                (D) considers nontraditional and
12            nonutility-owned investment alternatives that can
13            meet grid needs and provide additional benefits
14            (including consumer, economic and environmental
15            benefits) beyond comparable, traditional
16            utility-planned capital investments;
17                (E) equitably benefits environmental justice
18            communities; and
19                (F) maximizes consumer, environmental,
20            economic and community benefits.
21            (ii) The Commission, after notice and hearing,
22        shall modify each electric utility's Plan as necessary
23        to comply with the objectives of this Section. The
24        Commission may approve, or modify and approve, a Plan
25        only if it finds that the Plan is reasonable, complies
26        with the objectives and requirements of this Section,



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1        and reasonably incorporates input from parties. The
2        Commission's approval of any Plan does not constitute
3        approval, or any adjudication of the prudence or
4        reasonableness, of any expenditures associated with
5        the Plan. The Commission may reject each electric
6        utility's Plan if it finds that the Plan does not
7        comply with the objectives and requirements of this
8        Section. Where the Commission enters an Order
9        rejecting a Plan, the utility must refile a Plan
10        within 3 months after that Order, and until the
11        Commission approves a Plan, the utility's existing
12        Plan will remain in effect.
13            (iii) For all Integrated Grid Plan filings, the
14        Commission shall enter an order no later than 9 months
15        after the date of filing.
16            (iv) Each electric utility shall file its proposed
17        Initial Multi-Year Integrated Grid Plan no later than
18        June 1, 2022. Prior to that date and following the
19        Initiating Order, the Commission shall initiate a case
20        management conference and shall take any appropriate
21        steps to begin meaningful consideration of issues,
22        including enabling interested parties to begin
23        conducting discovery.
24        (6) Implementation Plans.
25            (i) As part of its order approving a utility's
26        Multi-Year Integrated Grid Plan, including any



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1        modifications required, the Commission shall create a
2        subsequent implementation plan docket, or multiple
3        implementation plan dockets, if the Commission
4        determines that multiple dockets would be preferable,
5        to consider the utility's detailed plans for:
6                (A) acquiring the level of demand response
7            resources specified in its approved Multi-Year
8            Integrated Grid Plan;
9                (B) acquiring the level of load flexibility or
10            energy storage resources specified in its approved
11            Multi-Year Integrated Grid Plan;
12                (C) achieving the level of transportation,
13            building and industry electrification specified in
14            its approved Multi-Year Integrated Grid Plan, or
15            implementing optimized charging or other
16            beneficial electrification programs;
17                (D) developing any of the plans, tariffs,
18            programs or policies required by paragraph (4) of
19            subsection (e) and additionally required by the
20            Commission in its Order regarding the Multi-Year
21            Integrated Grid Plan; and
22                (E) developing the Hosting Capacity and
23            Interconnection Analysis required by paragraph (2)
24            of subsection (f);
25                (F) developing a process to screen, analyze
26            and procure nonwires alternatives; and



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1                (G) addressing any other topic or resource
2            area covered by the utility's Multi-Year
3            Integrated Grid Plan for which the Commission
4            considers it important and necessary to receive
5            and approve a greater level of detail regarding
6            the utility's plans.
7            (ii) Each implementation plan shall include a
8        detailed explanation of:
9                (A) the projected costs (investments and
10            expenses) and benefits of each plan or program to
11            be considered in the implementation plan,
12            including related financial incentives, marketing,
13            and administration;
14                (B) categories and sub-categories of resources
15            or services to be acquired to achieve the
16            objectives in the Multi-Year Integrated Grid Plan
17            (for example, the implementation plan for demand
18            response shall identify the different types of
19            demand response resources that will collectively
20            be pursued to achieve the total level of demand
21            response capability approved in the Plan);
22                (C) the marketing, customer recruitment and
23            engagement, financial incentive, procurement
24            approach and other important elements of the plan
25            or program, including efforts to cultivate
26            qualifying customers in low-income and



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1            environmental justice communities;
2                (D) an explanation of how the proposed plans
3            or programs will be able to achieve the objective
4            in the Multi-Year Integrated Grid Plan;
5                (E) an analysis of how, exclusive of
6            low-income rate relief and other income-qualified
7            programs, the implementation plan will contribute
8            to the Multi-year Integrated Grid Plan's
9            requirement that at least 40% of benefits from
10            programs, policies, and initiatives will be
11            directed to low-income and environmental justice
12            communities;
13                (F) a discussion of any risk in the utility's
14            ability to acquire the planned levels of resource
15            acquisition within the approved budget, as well as
16            contingency plans for addressing such risks; and
17                (G) a plan for periodic (but at least
18            quarterly) engagement with stakeholders on the
19            rollout and implementation of the implementation
20            plans in order to inform them of plans and
21            progress, as well as to solicit input on
22            opportunities for improving plans and
23            implementation or on ways to modify plans as
24            needed.
25            (iii) The implementation plan dockets shall be
26        contested proceedings, with opportunities for



SB2295- 58 -LRB102 17361 SPS 22854 b

1        discovery and filing of testimony by interested
2        stakeholders. Each utility shall file its
3        implementation plans within 90 days after approval,
4        with any modifications, of its Multi-Year Integrated
5        Grid Plan.
6    (g) Subsequent Multi-Year Integrated Grid Plans. No later
7than June 1, 2025 and every 4 years thereafter, each electric
8utility subject to this Section shall file a new Multi-Year
9Integrated Grid Plan for the subsequent 4 delivery years after
10the completion of the then-effective Plan. Each Plan shall
11meet the requirements described in subsection (f), and shall
12be preceded by a workshop process which meets the same
13requirements described in subsection (e). If appropriate, the
14Commission may require additional implementation dockets to
15follow Subsequent Multi-Year Integrated Grid Plan filings.
16    (220 ILCS 5/16-107.7 new)
17    Sec. 16-107.7. Residential time-of-use pricing.
18    (a) The General Assembly finds that time-of-use rates and
19pricing plans can lower energy costs for consumers and reduce
20grid costs as well as help Illinois achieve its energy policy
21goals by improving load shape, encouraging energy
22conservation, and shifting usage away from periods where
23fossil fuels are used to meet peak demand. Further, by
24providing consumers information relating the costs of service
25to the time of energy usage, time-of-use rates can help



SB2295- 59 -LRB102 17361 SPS 22854 b

1consumers reduce their energy bills by using electricity when
2it is less costly. Time-of-use rates can help allocate
3electricity system costs more accurately and thus equitably to
4those who cause costs. Such rates can reduce the need for
5ramping resources and increase the grid's ability to
6cost-effectively integrate greater quantities of variable
7renewable energy and distributed energy resources.
8    (b) An electric utility that has a tariff in effect under
9Section 16-108.5 as of the effective date of this amendatory
10Act of the 102nd General Assembly shall also offer at least one
11market-based, time-of-use rate for eligible retail customers
12that choose to take power and energy supply service from the
13utility. The utility shall file its time-of-use rate tariff no
14later than 120 days after the effective date of this
15amendatory Act of the 102nd General Assembly, and each utility
16subject to this requirement shall implement the requirements
17of this paragraph by filing a tariff with the Commission. The
18tariff or tariffs shall be subject to the following
20        (1) If more than one tariff is proposed, at least one
21    tariff shall include at least 3 time blocks: a peak time
22    block defined as 2 p.m. to 7 p.m. on nonholiday weekdays or
23    the 5 consecutive hours best reflecting the highest system
24    peak demands, an off-peak time block defined as 10 a.m. to
25    2 p.m. and 7 p.m. to 10 p.m. on nonholiday weekdays or the
26    7 total hours, occurring in some combination before and



SB2295- 60 -LRB102 17361 SPS 22854 b

1    after the peak period, which reflect the next highest
2    system peak demands, and a super-off-peak time block
3    defined as all other hours including weekend days.
4        2) This tariff shall strive to achieve price ratios
5    between the blocks as follows: the super-off-peak time
6    block price shall be no less than zero but no greater than
7    one-half of the price of the off-peak time block price,
8    and the off-peak time block price shall be no greater than
9    one-half of the price of the peak time block price.
10        (3) The time-of-use rate shall include the costs of
11    electric capacity, costs of transmission services, and
12    charges for network integration transmission service,
13    transmission enhancement, and locational reliability, as
14    these terms are defined in the PJM Interconnection LLC
15    Open Access Transmission Tariff and manuals on January 1,
16    2019, within the prices for each time block and seasonal
17    block in which the associated costs generally are
18    incurred. If the Open Access Transmission Tariff or
19    manuals subsequently renames those terms, the services
20    reflected under those terms shall continue to be included
21    in the time-of-use rate described in this paragraph (2).
22        (4) Adjustments to the charges set by the tariff may
23    be made on a semi-annual basis, as follows: each May and
24    November, the utility shall submit to the Commission,
25    through an informational filing, its updated charges, and
26    such charges shall take effect beginning with the June



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1    monthly billing period and December monthly billing
2    period, respectively.
3        (5) The tariff shall include a purchased energy
4    adjustment to fully recover the supply costs for the
5    customers taking service under this tariff.
6    "Eligible customers" includes, but is not limited to,
7customers participating in net electricity metering under the
8terms of Section 16-107.5.
9    (c) The Commission shall, after notice and hearing,
10approve the tariff or tariffs with modifications the
11Commission finds necessary to improve the program design,
12customer participation in the program, or coordination with
13existing utility pricing programs, energy efficiency programs,
14demand response programs, and any other programs supporting
15Illinois energy policy goals and the integration of
16distributed energy resources. The Commission shall also
17consider how the proposed time-of-use rate design reflects the
18system costs and usage patterns of the utility. A proceeding
19under this subsection may not exceed 120 days in length.
20    (d) If the Commission issues an order pursuant to this
21subsection, the affected electric utility shall contract with
22an entity not affiliated with the electric utility to serve as
23a program administrator to develop and implement a program to
24provide consumer outreach, enrollment, and education
25concerning time-of-use pricing and to establish and administer
26an information system and technical and other customer



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1assistance that is necessary to enable customers to manage
2electricity use. The program administrator: (i) shall be
3selected and compensated by the electric utility, subject to
4Commission approval; (ii) shall have demonstrated technical
5and managerial competence in the development and
6administration of demand management programs; and (iii) may
7develop and implement risk management, energy efficiency, and
8other services related to energy use management for which the
9program administrator shall be compensated by participants in
10the program receiving such services. The electric utility
11shall provide the program administrator with all information
12and assistance necessary to perform the program
13administrator's duties, including, but not limited to,
14customer, account, and energy use data. The electric utility
15shall permit the program administrator to include inserts in
16residential customer bills 2 times per year to assist with
17customer outreach and enrollment.
18    The program administrator shall submit an annual report to
19the electric utility no later than April 1 of each year
20describing the operation and results of the program, including
21information concerning the number and types of customers using
22the program, changes in customers' energy use patterns, an
23assessment of the value of the program to both participants
24and nonparticipants, and recommendations concerning
25modification of the program and the tariff or tariffs filed
26under this Section. This report shall be filed by the electric



SB2295- 63 -LRB102 17361 SPS 22854 b

1utility with the Commission within 30 days after receipt and
2shall be available to the public on the Commission's website.
3    (e) Once the tariff or tariffs has been in effect for 24
4months, the Commission may, upon complaint, petition, or its
5own initiative, open a proceeding to investigate whether
6changes or modifications to the tariff or tariffs, program
7administration and any other program design element is
8necessary to achieve the goals described in subsection (a) of
9this Section. Such a proceeding may not last more than 120 days
10from the date upon which the investigation is opened by
11Commission order.
12    (f) An electric utility shall be entitled to recover
13reasonable costs incurred in complying with this Section,
14provided that recovery of the costs is fairly apportioned
15among its residential customers.
16    (g) The electric utility's tariff or tariffs filed
17pursuant to this Section shall be subject to the provisions of
18Article IX of this Act insofar as they do not conflict with
19this Section.
20    (h) This Section does not apply to any electric utility
21providing service to 100,000 or fewer customers.
22    (220 ILCS 5/16-108.18 new)
23    Sec. 16-108.18. Performance-based ratemaking.
24    (a) Findings and Purpose. The General Assembly finds that
25improving the alignment of utility customer and company



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1interests is critical to ensuring that Illinois residents and
2businesses have the opportunity to optimize existing utility
3infrastructure and do not suffer economic and environmental
4harm from the State's energy systems. This realignment is
5critical to ensure the ongoing viability of Illinois electric
6utilities, as they face an increasing need to rapidly adopt
7business models and strategies that enable new innovations and
8customer choices. Furthermore, the General Assembly finds that
9this realignment has entered a period of extraordinary
10urgency, given the expected rapid growth of distributed energy
11resources, electric vehicles, and other new technologies that
12substantially change the makeup of the grid. Moreover, urgency
13of action to address increasing threats from climate change
14and to assist communities that have borne a disproportionate
15impact from air pollution, greenhouse gas emissions, and
16energy burdens requires immediate and significant change to
17the business model under which utilities in Illinois have
18functioned. Providing incentive for necessary changes through
19a new holistic, performance-based structure for ratemaking
20will enable alignment of utility, customer, community and
21environmental goals. In particular, the General Assembly finds
23        (1) The traditional regulatory model rewards utilities
24    for increasing capital expenditures by basing allowed
25    revenues on the value of the rate base, irrespective of
26    utility performance. This compact does not align the



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1    interests of customers and utilities because it may result
2    in a bias toward expending utility capital in ways that
3    may displace more efficient or cost-effective options,
4    such as distributed energy resources owned by customers or
5    projects implemented by independent third parties that can
6    meet grid needs.
7        (2) Traditional regulation also rewards utilities for
8    selling higher volumes of electricity through the
9    throughput incentive. This model unnecessarily increases
10    customer costs and pollution and is therefore in neither
11    ratepayers' nor the State's interest.
12        (3) Though Illinois has taken some measures to move
13    utilities to performance-based ratemaking through the
14    establishment of performance incentives and a
15    performance-based formula rate under the Energy
16    Infrastructure Modernization Act, these measures have not
17    been transformative in urgently moving electric utilities
18    toward the State's ambitious energy policy goals:
19    protecting a healthy environment and climate, improving
20    public health, and creating quality jobs and economic
21    opportunities including wealth building, especially in
22    economically disadvantaged communities and BIPOC
23    communities. Rather, they have resulted in excess utility
24    profits without meaningful improvements in customer
25    experience, rates, or equity.
26        (4) The General Assembly therefore directs the



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1    Illinois Commerce Commission to complete a transition to a
2    comprehensive performance-based regulation framework for
3    electric utilities with more than 500,000 customers. The
4    breadth of this framework should remake existing utility
5    regulations to position Illinois electric utilities to
6    effectively and efficiently achieve current and
7    anticipated future energy needs of this State.
8        (5) It is the intent of the General Assembly that over
9    time the comprehensive performance-based regulation
10    framework will progressively reduce the direct link
11    between utility revenues and traditional investment levels
12    and increasingly tie revenues to performance.
13    (b) Definitions.
14    As used in this Section:
15    "Commission" means the Illinois Commerce Commission.
16    "Demand response" means measures that decrease peak
17electricity demand or shift demand from peak to off-peak
19    "Distributed energy resources" or "DER" means a wide range
20of technologies that are located on the customer side of the
21customer's electric meter and can provide value to the
22distribution system, including, but not limited to,
23distributed generation, energy storage, electric vehicles, and
24demand response technologies.
25    "Economically disadvantaged communities" means areas of
26one or more census tracts where average household income does



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1not exceed 80% of area median income.
2    "Environmental justice communities" means the definition
3of that term based on existing methodologies and findings,
4used and as may be updated by the Illinois Power Agency and its
5Program Administrator in the Illinois Solar for All Program.
6    "Performance-based regulation or ratemaking" or "PBR"
7means a regulatory approach that aligns utility interests with
8customer and societal interests through regulatory mechanisms
9that motivate utilities to improve operations, increase
10program effectiveness, better manage business expenses, and
11align system performance with identified societal or policy
13    (c) Objectives. The comprehensive PBR framework should be
14designed to accomplish the following objectives:
15        (1) incentivize utilities to pursue cost-effective
16    solutions to meet customer needs;
17        (2) decarbonize utility systems at a pace that meets
18    or exceeds state climate goals;
19        (3) remove utility incentives to grow energy sales,
20    except where sales growth is determined to be aligned with
21    state policy goals;
22        (4) reduce the link between utility expenditures and
23    collected revenue and eliminate embedded utility
24    preferences for one type of expenditure over another for
25    the same service;
26        (5) incentivize utilities to undertake the most



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1    effective expenditures for assets or services, whether
2    self-supplied by the utility or through third-party
3    contracting, to deliver high-quality service to customers
4    at least cost;
5        (6) maintain the affordability, safety, and
6    reliability of electric power supply; and
7        (7) incentivize utilities to pursue equitable access
8    to high-quality customer service, affordable rates, DER
9    interconnection, and the benefits of grid modernization
10    and clean energy for ratepayers in environmental justice
11    and economically disadvantaged communities. Additionally,
12    motivate utilities to sustain a diverse workforce,
13    supplier procurement base and, for relevant programs,
14    approved vendor pools.
15    (d) The comprehensive PBR framework should comprise a set
16of PBR mechanisms that collectively accomplish the objectives
17set forth in subsection (c). Those mechanisms may include, but
18are not limited to:
19        (1) Multi-Year Rate Plans and associated features, as
20    set forth in subsection (e) of this Section;
21        (2) revenue decoupling, as set forth in paragraph (11)
22    of subsection (e) of this Section;
23        (3) shared savings mechanisms;
24        (4) performance incentive mechanisms, as set forth in
25    subsection (f) of this Section;
26        (5) changes to the accounting treatment of capital and



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1    operating expenditures; and
2        (6) changes to rate design, as set forth in Section
3    paragraph 10 of subsection (e) of this Section.
4    (e) Multi-Year Rate Plan.
5        (1) If an electric utility has a performance-based
6    formula rate in effect under Section 16-108.5 as of
7    December 31, 2020, then the utility shall file a petition
8    proposing tariffs implementing a 4-year Multi-Year Rate
9    Plan as provided in this Section no later than July 1, 2022
10    for delivery service rates to be effective from June 1,
11    2023 through May 31, 2027. The Commission shall issue an
12    order approving, approving as modified, or rejecting the
13    utility's plan no later than June 1, 2023. If the
14    Commission rejects the utility's plan, the deadline to
15    approve the plan or approve it as modified shall be
16    extended to 4 months from the date of the rejection. The
17    term "Multi-Year Rate Plan" refers to a plan establishing
18    the rates the utility may charge for each delivery year of
19    the 4-year period to be covered by the plan. The net
20    revenue requirement reflected in rates in effect on
21    December 31, 2021 for the electric utility shall remain in
22    effect until new rates are approved under the Multi-Year
23    Rate Plan, and no additional annual reconciliation under
24    Section 16-108.5 shall be made.
25        (2) A utility proposing a Multi-Year Rate Plan shall
26    provide a description of the utility's major planned



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1    investments, which shall include at a minimum all
2    investments of $1,000,000 or greater over the plan period.
3    Planned investments must conform to the goals established
4    in the Multi-Year Integrated Grid Plan described in
5    Section 16-105.17 of this Act.
6        (3) The Multi-Year Rate Plan shall be implemented
7    through a tariff filed with the Commission consistent with
8    the provisions of this paragraph (3) that shall apply to
9    all delivery service customers. The Commission shall
10    initiate and conduct an investigation of the tariff in a
11    manner consistent with the provisions of this paragraph
12    (3) and the provisions of Article IX of this Act to the
13    extent they do not conflict with this paragraph (3). The
14    Multi-Year Rate Plan approved by the Commission shall do
15    the following:
16            (A) Provide for the recovery of the utility's
17        forecasted rate base, based on a budget forecast or a
18        fixed escalation rate, individually or in combination.
19        The forecasted rate base must include the utility's
20        planned capital investments and investment-related
21        costs, including income tax impacts, depreciation, and
22        property taxes prudently incurred and reasonable in
23        amount consistent with Commission practice and law.
24        The budgeting process must be iterative, be rigorous,
25        and lead to forecasts that reasonably represent the
26        utility's investments during the forecasted period.



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1            (B) For the first Multi-Year Rate Plan, reflect
2        year-end capital structure that includes a common
3        equity ratio, excluding goodwill, of no more than 50%
4        of the total capital structure shall be deemed
5        reasonable and prudent and used to set rates.
6            (C) For the first Multi-Year Rate Plan, include a
7        cost of equity, which shall be calculated as the sum of
8        the following:
9                (i) the average for the applicable calendar
10            year of the monthly average yields of 30-year U.S.
11            Treasury bonds published by the Board of Governors
12            of the Federal Reserve System in its weekly H.15
13            Statistical Release or successor publication; and
14                (ii) 530 basis points.
15            At such time as the Board of Governors of the
16        Federal Reserve System ceases to include the monthly
17        average yields of 30-year U.S. Treasury bonds in its
18        weekly H.15 Statistical Release or successor
19        publication, the monthly average yields of the U.S.
20        Treasury bonds then having the longest duration
21        published by the Board of Governors in its weekly H.15
22        Statistical Release or successor publication shall
23        instead be used for purposes of this subparagraph (C).
24            (D) For subsequent Multi-Year Rate Plans, the cost
25        of equity and capital structure shall be established
26        by the Commission and shall be set to reflect a



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1        risk-adjusted return compared to the prevailing cost
2        of capital and comparable investments in the economy,
3        including U.S. Treasury rates, upon which additional
4        earning opportunities and penalties can be provided to
5        reflect utility performance against identified
6        outcomes.
7            (E) Recovery of operations and maintenance
8        expenses, based on projected costs, an
9        electricity-related price index or other formula.
10            (F) Amortize the amount of unprotected
11        property-related excess accumulated deferred income
12        taxes in rates as of December 31, 2022 over a period of
13        5 years.
14            (G) Disallow recovery of charitable contributions.
15            (H) Allow recovery of pension and other
16        post-employment benefits expense only if such costs
17        are demonstrated to be funded by ratepayers.
18            (I) Allow recovery of incentive compensation
19        expense that is based on the achievement of
20        operational metrics, including metrics related to
21        budget controls, outage duration and frequency,
22        safety, customer service, efficiency and productivity,
23        environmental compliance and attainment of
24        environmental goals, and other goals and metrics
25        approved by the Commission. 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;
2        (4) Rates charged under the Multi-Year Rate Plan must
3    be based only upon the utility's reasonable and prudent
4    costs of service over the term of the plan, as determined
5    by the Commission, provided that the costs are not being
6    recovered elsewhere in rates. Rate adjustments authorized
7    by the Commission may continue outside of a plan
8    authorized under this Section to the extent such costs are
9    not recovered elsewhere in rates. The burden of proof
10    shall be on the electric utility to establish the prudence
11    of investments and expenditures and to establish that such
12    investments are reasonably necessary to meet the
13    requirements of the most recently approved Multi-Year
14    Integrated Grid Plan described in Section 16-105.17 of
15    this Act. The sole fact that a cost differs from that
16    incurred in a prior period or that an investment is
17    different from that described the Multi-year Integrated
18    Grid Plan shall not imply the imprudence or
19    unreasonableness of that cost or investment. The sole fact
20    that an investment is the same or similar to that
21    described in the Multi-Year Integrated Grid Plan shall not
22    imply prudence and reasonableness.
23        (5) To facilitate public transparency, all materials,
24    data, testimony, schedules, etc. shall be provided to the
25    Commission in an editable, machine-readable electronic
26    format including .doc, .docx, .xls, .xlsx, and similar,



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1    but not including .pdf or .exif. Should utilities
2    designate any materials "confidential," they shall have an
3    affirmative duty to explain why the particular information
4    is marked confidential. In determining prudence and
5    reasonableness of rates, the Commission shall also
6    consider each public comment filed in the docket.
7        (6) The Commission may, by order, establish terms,
8    conditions, and procedures for a Multi-Year Rate Plan
9    necessary to implement this Section and ensure that rates
10    remain just and reasonable during the course of the plan,
11    including terms and procedures for rate adjustment. At any
12    time prior to conclusion of a Multi-Year Rate Plan, the
13    Commission, upon its own motion or upon petition of any
14    party, may initiate a proceeding to examine the
15    reasonableness of the utility's rates under the plan, and
16    adjust rates as necessary.
17        (7) Capital True-up. The utility shall propose an
18    annual capital true-up mechanism that provides a refund to
19    customers if the utility's actual capital-related revenue
20    requirement is less in total in any of the Multi-Year Rate
21    Plan delivery years than the Commission authorizes for
22    that year. Conversely, if the Company's actual
23    capital-related revenue requirement is more in total in
24    the Multi-year Rate Plan delivery year than the Commission
25    authorizes for that year, the Company cannot surcharge
26    customers to collect any under recovery.



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1        (8) A participating utility that files a tariff
2    pursuant to paragraph (3) of this subsection (e) must
3    submit a one-time $200,000 filing fee at the time the
4    Chief Clerk of the Commission accepts the filing, which
5    shall be a recoverable expense.
6        (9) Subsequent Multi-Year Rate Plans. An electric
7    utility operating under the Multi-Year Rate Plan shall
8    file a new Multi-Year Rate Plan at least 210 days prior to
9    the end of the initial Multi-Year Rate Plan, and every 4
10    years thereafter, with a rate-effective date of the
11    proposed tariffs such that, after the Commission
12    suspension period, the rates would take effect immediately
13    at the close of the final year of the initial Multi-Year
14    Rate Plan. In subsequent Multi-Year Rate Plans, as in the
15    initial plans, utilities and stakeholders may propose
16    additional metrics that achieve the outcomes described in
17    paragraph (2) of subsection (f) of this Section.
18        (10) Rate Design. The Commission shall approve tariffs
19    as part of each Multi-Year Rate Plan establishing rate
20    design for all delivery service customers. These shall
21    expand the rate options available to customers, including,
22    but not limited to, an affordability rate for low-income
23    residential customers, a time-of-use rate, an electric
24    vehicle rate, and a peak time savings rate.
25        (11) Decoupling. The Commission may, by order, approve
26    a tariff filed by an electric utility that provides for



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1    decoupling of sales and revenues to mitigate the impact on
2    public utilities of the energy-savings goals and to reduce
3    a utility's disincentive to promote energy efficiency
4    under Section 16-111.5B of this Act without adversely
5    affecting utility ratepayers. In its consideration of a
6    proposed decoupling tariff, the Commission shall consider
7    a mechanism that triggers the periodic adjustment to rates
8    when the changes in revenue would result in a change
9    within a certain percentage, an earnings band to share
10    revenues that exceed the authorized return, or other
11    mechanisms that reduce the size and frequency of rate
12    adjustments.
13    (f) Performance Incentive Mechanisms.
14        (1) The Commission shall establish performance
15    incentive mechanisms in order to better tie utility
16    revenues to performance and customer benefits, accelerate
17    progress on Illinois energy and other goals, and hold
18    utilities publicly accountable. The Commission shall
19    develop metrics, which are observable and measurable
20    indicators of system or utility performance, in order to
21    create performance incentive mechanisms. Specifically, the
22    Commission shall establish:
23            (A) Tracking metrics, which will be used for
24        measuring and reporting utility performance.
25            (B) Performance metrics, which will be used for
26        financially incentivizing improved utility



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1        performance.
2        (2) Outcomes of Metrics. The Commission shall approve
3    tracking and performance metrics that encourage
4    cost-effective, equitable utility achievement of the
5    following outcomes:
6            (A) Affordability. Achieve affordable customer
7        energy costs and utility bills, with particular
8        emphasis on keeping lower-income households' bills
9        within a manageable portion of their income.
10            (B) Pollution Reduction. Minimize emissions of
11        greenhouse gases and pollutants that harm human
12        health, particularly in environmental justice and
13        economically disadvantaged communities, through both
14        (A) minimizing emissions per kilowatt-hour of
15        electricity consumed; and (B) minimizing total
16        emissions, including by accelerating electrification
17        of transportation, buildings and industries where such
18        electrification results in net reductions, across all
19        fuels and over the life of electrification measures,
20        of greenhouse gases and other pollutants.
21            (C) Flexibility. Enhance the grid's flexibility to
22        adapt to increased deployment of nondispatchable
23        resources; improve the ability and performance of the
24        grid on load balancing; and address uncertainty around
25        future customer needs, future environmental concerns,
26        emerging technology, changes in costs of technology



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1        and service, and other factors.
2            (D) Reliability. Meet high standards of overall
3        and locational reliability.
4            (E) Customer Experience. Deliver customer service
5        quality, customer engagement, and customer access to
6        utility system information.
7            (F) Equity. Maximize and prioritize the allocation
8        of grid planning benefits to environmental justice and
9        economically disadvantaged customers and communities.
10        Sustain a diverse workforce, supplier procurement base
11        and, for relevant programs, approved vendor pools.
12            (G) Cost-effectiveness. Ensure rates reflect cost
13        savings attributable to grid modernization and
14        integration of distributed energy resources that allow
15        the utility to defer or forgo traditional grid
16        investments that would otherwise be required.
17        It is the intent of the General Assembly that these
18    outcomes shall guide the development of metrics even as
19    the grid, along with its associated technologies and
20    policies, evolves. It is also the intent of the General
21    Assembly that the limitation of total costs to customers
22    and the promotion of ethical and transparent practices by
23    utilities, as well as the role that flexible load and
24    distributed energy resources can play in advancing the
25    outcomes, be considered in the establishment of metrics.
26        (3) Metrics Requirements.



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1            (A) Tracking Metrics. Tracking metrics shall
2        entail a description of the metric, a calculation
3        method, and a data collection method. The Commission
4        shall approve tracking metrics that measure
5        achievement of at least one of the outcomes set forth
6        in paragraph (2) and are supported by sufficient
7        stakeholder input. Tracking metrics should measure
8        outcomes and actual results and projections where
9        possible.
10            (B) Performance Metrics. Performance metrics shall
11        entail a description of the metric, a calculation
12        method, a data collection method, annual binding
13        performance targets, and monetary incentives (rewards
14        or penalties or both, depending on the metric) for
15        utilities' achievement of or failure to achieve their
16        performance targets. The Commission shall approve
17        performance metrics that (i) measure achievement of
18        the outcomes set forth in paragraph (2); (ii) are
19        supported by sufficient stakeholder input; (iii) have
20        one year of tracking data collected in a consistent
21        manner and verifiable by an independent evaluator in
22        order to establish a baseline; and (iv) require an
23        incentive (reward or penalty or both) to create
24        improved utility performance. While a single
25        performance metric may measure achievement of more
26        than one of the outcomes set forth in paragraph (2),



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1        and such metrics should be valued, the Commission
2        shall not approve multiple performance metrics that
3        measure achievement identical or near-identical
4        results. Performance metrics should measure outcomes
5        and actual, rather than projected, results where
6        possible.
7            (C) Performance targets. For metrics where
8        progressive improvement is desirable, performance
9        targets shall increase annually and shall require
10        utilities to perform beyond "business as usual," as
11        determined by baseline tracking data and
12        high-confidence projections. Increases to a target
13        shall be considered in light of other metrics,
14        cost-effectiveness, and other factors the Commission
15        deems appropriate.
16            (D) Performance incentives. The Commission shall
17        determine whether and to what extent each performance
18        metric shall offer a reward, penalty, or both to a
19        utility. For metrics where a reward is offered, and
20        that reward is a cash payment, the reward shall be
21        calculated as a percentage of net benefits from the
22        outcome, net of costs to customers. The Commission
23        shall develop a methodology to calculate net benefits
24        that includes societal costs and benefits.
25            In determining the appropriate level of a reward
26        or penalty, the Commission shall consider: the extent



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1        to which the amount is likely to encourage the utility
2        to achieve the performance target in the least cost
3        manner; the value of benefits to customers, the grid,
4        and the environment from achievement of the
5        performance target, including in particular benefits
6        to environmental justice and economically
7        disadvantaged communities; customer bill
8        affordability; the utility's revenue requirement; and
9        other such factors that the Commission deems
10        appropriate. The consideration of these factors shall
11        result in an incentive level that ensures benefits
12        exceed costs for customers.
13            The rewards or penalties shall be calculated based
14        on the electric utility achieving performance targets.
15        In determining the specific rewards or penalties, the
16        Commission shall give proportionate weight to the
17        following set of metrics: affordability,
18        cost-effectiveness, pollution reduction, flexibility,
19        customer experience, reliability, and equity.
20            It is the intent of the General Assembly that over
21        time the utility's cost of equity shall be
22        progressively reduced while the opportunity to grow
23        earnings as a result of achieving performance targets
24        shall be progressively increased as the Commission
25        establishes new performance metrics.
26    (g) Initial Metrics. The Commission shall initiate a



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14-month workshop process no later than March 1, 2022 for the
2purpose of informing the enactment of metrics. The workshop
3shall be facilitated by Staff of the Illinois Commerce
4Commission, and shall be organized and facilitated in a manner
5that encourages representation from diverse stakeholders,
6ensuring equitable opportunities for participation, without
7requiring formal intervention or representation by an
8attorney. Following the workshop, the Commission shall
9establish initial tracking and performance metrics in a
10docketed proceeding that shall be filed by the electric
11utility by July 2, 2022. The initial tracking and performance
12metrics shall be in place for the period of the first
13Multi-Year Rate Plan. The proceeding shall conclude, and the
14commission shall issue an order in the matter, no later than
15April 1, 2023.
16    Unless the tracking metrics in subparagraph (3) of
17paragraph (A) and performance metrics in subparagraph (3) of
18paragraph (B) of subsection (f) of this Section are found by
19the Commission during initial metric-setting proceeding to not
20meet the requirements set forth in this Section, the
21Commission shall approve these metrics, and it shall establish
22calculations and goals for the tracking metrics set forth in
23subparagraph (3) of paragraph (A) of subsection (f) of this
24Section and calculations, targets, and incentives for the
25tracking metrics set forth in subparagraph (3) of paragraph
26(B) of subsection (f) of this Section. If the Commission finds



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1that the metrics set forth in subparagraph (3) of paragraph
2(A) and subparagraph (3) of paragraph (B) of subsection (f) of
3this Section do not meet the requirements set forth in this
4Section, then the Commission shall approve substitute metrics.
5The Commission may also approve additional tracking and
6performance metrics as appropriate if they meet the
7requirements set forth in this Section.
8    Initial Performance Metrics shall include at a minimum,
9but not limited to, the following:
10        (1) system Average Interruption Frequency Index;
11        (2) customer Average Interruption Duration Index; and
12        (3) peak load reductions enabled by demand response
13    programs.
14    (h) Future Metrics. The Commission shall establish new
15tracking and performance metrics in future Annual Performance
16Evaluation proceedings to further measure achievement of the
17outcomes set forth in paragraph (2) of subsection (f) of this
18Section and the other goals and requirements of this Section.
19    The Commission shall also evaluate metrics that were
20established in prior Annual Performance Evaluation proceedings
21under the procedures set forth in subsection (i) to determine
22if adjustments are required to improve the likelihood of the
23outcomes described in paragraph (2) of subsection (f). For
24metrics that were established in prior Annual Performance
25Evaluation proceedings and that the Commission elects to
26continue, the design of these metrics, including the goals of



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1tracking metrics and the targets and incentive levels and
2structures of performance metrics, may be adjusted pursuant to
3the requirements in this Section. The Commission may also
4phase out tracking and performance metrics that were
5established in prior Annual Performance Evaluation proceedings
6if these metrics no longer meet the requirements of this
7Section or if they are rendered obsolete by the changing needs
8and technology of an evolving grid. Additionally, performance
9metrics that no longer require an incentive to create improved
10utility performance may become tracking metrics.
11    In service of the outcomes set forth in paragraph (2) of
12subsection (f), it is the intent of the General Assembly that
13the Commission in future Annual Performance Evaluation
14proceedings establish the tracking metrics and performance
15metrics set forth in subparagraph (A) and subparagraph (B) of
16paragraph (3) of subsection (f) of this Section when these
17metrics would be compliant with the requirements set forth in
18this Section.
19    (i) Annual Performance Evaluation. On June 1 of each year,
20following the approval of the first Multi-Year Rate Plan and
21its initial delivery year, the Commission shall open an Annual
22Performance Evaluation proceeding to evaluate the utilities'
23performance on their metric targets during the delivery year
24just completed and accordingly determine rewards or penalties
25or both to be reflected in rates in the following calendar



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1        (1) Utility Reporting. On April 1 of each year, prior
2    to the Annual Performance Evaluation proceeding, each
3    participating utility shall file a Performance Evaluation
4    Report with the Commission that includes a description of
5    and all data supporting how the participating utility
6    performed under each tracking and performance metric and
7    an identification of any extraordinary events that
8    adversely impacted the utility's performance. The
9    Performance Evaluation Report shall be verified by an
10    independent evaluator as set out in paragraph (3) of this
11    subsection (i) and shall include both a report made to the
12    Commission and a short, public-facing scorecard that makes
13    this information publicly accessible and easily
14    understandable. The Commission shall post each scorecard
15    upon receipt on the Commission's web page in an
16    easily-accessible location. The format of the report and
17    the scorecard shall be consistent across utilities and
18    shall include:
19            (A) a list of metrics to which the utility is
20        subject;
21            (B) the previous delivery year's calculation
22        methods and performance on metrics if applicable;
23            (C) the current delivery year's calculation
24        methods and a detailed description of the effect of
25        any differences;
26            (D) the current-year goals for tracking metrics



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1        and current-year targets for performance metrics;
2            (E) the current year's performance on metrics
3        targets;
4            (F) a summary of the investments and programs
5        undertaken in order to achieve those metrics targets;
6        and (G) the annual goals and targets for the remaining
7        years of the current Multi-Year Rate Plan period.
8        Within 30 days after the Commission's Order in the
9    utility's Annual Performance Evaluation and Adjustment
10    filing, the utility shall update the public scorecard with
11    any changes required by the Commission and the revised
12    scorecard shall be posted on the Commission's website.
13        (2) Public Workshops. Preceding each Annual
14    Performance Evaluation, no later than April 1 each year,
15    the Commission shall initiate a two-month workshop
16    process. The workshops shall be facilitated by Staff of
17    the Illinois Commerce Commission, and shall be organized
18    and facilitated in a manner that encourages representation
19    from diverse stakeholders, ensuring equitable
20    opportunities for participation, without requiring formal
21    intervention or representation by an attorney. During
22    these workshops, each electric utility shall publicly
23    present its performance on tracking and performance
24    metrics following the requirements set forth in paragraph
25    (1) of this subsection (i). The electric utility shall
26    also explain how it has holistically considered the plans,



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1    programs, tariffs and policies and its Multi-Year
2    Integrated Grid Plan in order to achieve its metric
3    targets. Members of the public shall have opportunity for
4    comment and feedback. A summary of that feedback shall be
5    provided in an exhibit submitted by Staff of the Illinois
6    Commerce Commission in the Annual Performance Evaluation.
7        (3) Independent Evaluation. The electric utility shall
8    provide for an annual independent evaluation of its
9    performance on metrics. The independent evaluator shall
10    review the utility's assumptions, baselines, targets,
11    calculation methodologies, and other relevant information,
12    especially ensuring that the utility's data for
13    establishing baselines matches actual performance, and
14    shall provide a Report to the Commission in each Annual
15    Performance Evaluation describing the results. The
16    independent evaluator shall present this Report as
17    evidence as a nonparty participant. The independent
18    evaluator shall be hired through a competitive bidding
19    process.
20        The Commission shall consider the Report of the
21    independent evaluator in determining the utility's
22    achievement of performance targets. Discrepancies between
23    the utility's assumptions, baselines, targets, or
24    calculations and those of the independent evaluator shall
25    be closely scrutinized by the Commission. If the
26    Commission finds that the utility's reported data for any



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1    metric or metrics significantly deviates from the data
2    reported by the independent evaluator, then the Commission
3    shall order the utility to revise its data collection and
4    calculation process within 60 days, with specifications
5    where appropriate.
6        (4) Performance Adjustment. The Commission shall,
7    after notice and hearing in the Annual Performance
8    Evaluation proceeding, enter an order approving the
9    utility's performance adjustment based on its achievement
10    of or failure to achieve its performance targets no later
11    than December 31 each year. The Commission-approved
12    penalties or rewards shall be applied beginning with the
13    next calendar year. Nothing in this Section shall
14    authorize the Commission to reduce or otherwise obviate
15    the imposition of financial rewards or penalties for
16    achieving or failing to achieve one or more of the
17    utility's performance targets.
18        (5) Revisions to Metrics. While tracking and
19    performance metrics, along with their associated goals,
20    targets, and incentives, shall not be changed outside of
21    the Annual Performance Evaluation, the Commission may open
22    an investigation into the methodology, including
23    assumptions and calculations, used to measure or quantify
24    progress toward goals and targets in the Annual
25    Performance Evaluation at the request of an intervening
26    party.



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1    Section 99. Effective date. This Act takes effect upon
2becoming law.



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2 Statutes amended in order of appearance
3    New Act
4    5 ILCS 100/5-45.8 new
5    30 ILCS 105/5.935 new
6    220 ILCS 5/2-107from Ch. 111 2/3, par. 2-107
7    220 ILCS 5/4-605 new
8    220 ILCS 5/9-220.3
9    220 ILCS 5/9-227from Ch. 111 2/3, par. 9-227
10    220 ILCS 5/10-104from Ch. 111 2/3, par. 10-104
11    220 ILCS 5/16-105.17 new
12    220 ILCS 5/16-107.7 new
13    220 ILCS 5/16-108.18 new