220 ILCS 5/ Public Utilities Act.

(220 ILCS 5/16-104)

Sec. 16-104. Delivery services transition plan. An electric utility shall provide delivery services to retail customers in accordance with the provisions of this Section.

(a) Each electric utility shall offer delivery services to retail customers located in its service area in accordance with the following provisions:

(1) On or before October 1, 1999, the electric utility shall offer delivery services (i) to any non-residential retail customer whose average monthly maximum electrical demand on the electric utility's system during the 6 months with the customer's highest monthly maximum demands in the 12 months ending June 30, 1999 equals or exceeds 4 megawatts; (ii) to any non-governmental, non-residential, commercial retail customers under common ownership doing business at 10 or more separate locations within the electric utility's service area, if the aggregate coincident average monthly maximum electrical demand of all such locations during the 6 months with the customer's highest monthly maximum electrical demands during the 12 months ending June 30, 1999 equals or exceeds 9.5 megawatts, provided, however, that an electric utility's obligation to offer delivery services under this clause (ii) shall not exceed 3.5% of the maximum electric demand on the electric utility's system in the 12 months ending June 30, 1999; and (iii) to non-residential retail customers whose annual electric energy use comprises 33% of the kilowatt-hour sales, excluding the kilowatt-hour sales to customers described in clauses (i) and (ii), to each non-residential retail customer class of the electric utility.

(2) On or before October 1, 2000, the electric utility shall offer delivery services to the eligible governmental customers described in subsections (a) and (b) of Section 16-125A if the aggregate coincident average monthly maximum electrical demand of such customers during the 6 months with the customers' highest monthly maximum electrical demands during the 12 months ending June 30, 2000 equals or exceeds 9.5 megawatts.

(2.5) On or before June 1, 2000, an electric utility serving more than 1,000,000 customers in this State shall offer delivery services to retail customers whose annual electric energy use comprises 33% of the kilowatt hour sales to that group of retail customers that are classified under Division D, Groups 20 through 39 of the Standard Industrial Classifications set forth in the Standard Industrial Classification Manual published by the United States Office of Management and Budget, excluding the kilowatt-hour sales to those customers that are eligible for delivery services pursuant to clause (1)(i), and shall offer delivery services to its remaining retail customers classified under Division D, Groups 20 through 39 on or before October 1, 2000.

(3) On or before December 31, 2000, the electric utility shall offer delivery services to all remaining nonresidential retail customers in its service area.

(4) On or before May 1, 2002, the electric utility shall offer delivery services to all residential retail customers in its service area.

The loads and kilowatt-hour sales used for purposes of this subsection shall be those for the 12 months ending June 30, 1999 for nonresidential retail customers. The electric utility shall identify those customers to be offered delivery service pursuant to clause (1)(iii) and paragraph (2.5) of subsection (a) of this Section and Section 16-111(e)(B)(iii) pursuant to a lottery or other random nondiscriminatory selection process set forth in the electric utility's delivery services implementation plan pursuant to Section 16-105, which process may include a registration process giving each nonresidential customer the opportunity to register for eligibility for delivery services under this Section, with a lottery of registered customers to be conducted if the annual electric energy use of all registered customers exceeds the limit set forth in clause (1)(iii) or clause (2.5) or Section 16-111(e)(B)(iii), as applicable; provided that the provision of this amendatory Act of 1999 as it relates to the registration and lottery process under clause (1)(iii) is not intended to nor does it make any change in the meaning of this Section, but is intended to remove possible ambiguities, thereby confirming the existing meaning of this Section prior to the effective date of this amendatory Act of 1999. Provided, that non-residential retail customers under common ownership at separate locations within the electric utility's service area may elect, prior to the date the electric utility conducts the lottery or other random selection process for purposes of clause (1)(iii), to designate themselves as a common ownership group, to be excluded from such lottery and to instead participate in a separate lottery for such common ownership group pursuant to which delivery services will be offered to non-residential retail customers comprising 33% of the total kilowatt-hour sales to the common ownership group on or before October 1, 1999. For purposes of this subsection (a), an electric utility may define "common ownership" to exclude sites which are not part of the same business, provided, that auxiliary establishments as defined in the Standard Industrial Classification Manual published by the United States Office of Management and Budget shall not be excluded.

(b) The electric utility shall allow the aggregation of loads that are eligible for delivery services so long as such aggregation meets the criteria for delivery of electric power and energy applicable to the electric utility established by the regional reliability council to which the electric utility belongs, by an independent system operating organization to which the electric utility belongs, or by another organization responsible for overseeing the integrity and reliability of the transmission system, as such criteria are in effect from time to time. The Commission may adopt rules and regulations governing the criteria for aggregation of the loads utilizing delivery services, but its failure to do so shall not preclude any eligible customer from electing delivery services. The electric utility shall allow such aggregation for any voluntary grouping of customers, including without limitation those having a common agent with contractual authority to purchase electric power and energy and delivery services on behalf of all customers in the grouping.

(c) An electric utility shall allow a retail customer that generates power for its own use to include the electrical demand obtained from the customer's cogeneration or self-generation facilities that is coincident with the retail customer's maximum monthly electrical demand on the electric utility's system in any determination of the customer's maximum monthly electrical demand for purposes of determining when such retail customer shall be offered delivery services pursuant to clause (i) of subparagraph (1) of subsection (a) of this Section.

(d) The Commission shall establish charges, terms and conditions for delivery services in accordance with Section 16-108.

(e) Subject to the terms and conditions which the electric utility is entitled to impose in accordance with Section 16-108, a retail customer that is eligible to elect delivery services pursuant to subsection (a) may place all or a portion of its electric power and energy requirements on delivery services.

(f) An electric utility may require a retail customer who elects to (i) use an alternative retail electric supplier or another electric utility for some but not all of its electric power or energy requirements, and (ii) use the electric utility for any portion of its remaining electric power and energy requirements, to place the portion of the customer's electric power or energy requirement that is to be served by the electric utility on a tariff containing charges that are set to recover the lowest reasonably available cost to the electric utility of acquiring electric power and energy on the wholesale electric market to serve such remaining portion of the customer's electric power and energy requirement, reasonable compensation for arranging for and providing such electric power or energy, and the electric utility's other costs of providing service to such remaining electric power and energy requirement.

(Source: P.A. 90-561, eff. 12-16-97; 91-50, eff. 6-30-99.)

(220 ILCS 5/16-105)

Sec. 16-105. Delivery services implementation plan. To ensure the safe and orderly implementation of delivery services, each electric utility shall submit to the Commission no later than March 1, 1999, a delivery services implementation plan for non-residential customers and no later than August 1, 2001, a delivery services implementation plan for residential customers. The delivery services implementation plan shall detail the process and procedures by which each electric utility will offer delivery services to each customer class and shall be designed to insure an orderly transition and the maintenance of reliable service. The Commission shall enter an order approving, or approving as modified, the delivery services implementation plan of each electric utility no later than 60 days prior to the date on which the electric utility must commence offering such services.

(Source: P.A. 90-561, eff. 12-16-97.)

(220 ILCS 5/16-105.5)

Sec. 16-105.5. Rate case filing and revenue-neutral rate design.

(a) An electric utility that files a general rate case pursuant to Section 9-201 of this Act or a Multi-Year Rate Plan pursuant to Section 16-108.18 of this Act may omit the rate design component of such filing and subsequently separately file this component with the Commission, subject to the requirements of subsections (b) and (c) of this Section.

(b) If the electric utility makes the election described in this Section, then the filing shall be consistent with the rate design and cost allocation across customer classes approved in the Commission's most recent order regarding the electric utility's request for a general adjustment to its rates entered under Section 9-201, subsection (e) of Section 16-108.5, or Section 16-108.18 of this Act, as applicable.

(c) If the electric utility makes the election described in this Section, then the following provisions apply to the separate filing of the revenue-neutral rate design component:

(1) No later than one year after the tariffs implementing the general rate case filing or Multi-year Rate Plan filing, as described in subsection (b) of this Section, are placed into effect, the electric utility shall make a filing with the Commission that proposes changes to the tariffs to incorporate the findings of any final rate design orders of the Commission applicable to the electric utility and entered subsequent to the Commission's approval of the tariffs. If no such orders have been entered, then the electric utility must submit its separate revenue-neutral rate design filing no later than 3 years after the date on which the Commission's most recent final rate design order was entered for the electric utility. The electric utility's separate revenue-neutral rate design filing may either propose revenue-neutral tariff changes or refile the existing tariffs without change, which shall present the Commission with an opportunity to suspend the tariffs and consider revenue-neutral tariff changes related to rate design. The Commission shall, after notice and hearing, enter its order approving, or approving with modification, the proposed changes to the tariffs within 240 days after the electric utility's filing. Any changes ordered by the Commission shall become effective at the commencement of the first January monthly billing period that begins no earlier than 30 days after the Commission issues its order adopting such changes.

(2) Following Commission approval under paragraph (1) of this subsection (c), the electric utility shall make a filing with the Commission during each subsequent 3-year period that either proposes revenue-neutral tariff changes or refiles the existing tariffs without change, which shall present the Commission with an opportunity to suspend the tariffs and consider revenue-neutral tariff changes related to rate design. The requirements of this paragraph (2) shall terminate at the time that the electric utility files a general rate case or Multi-Year Rate Plan that includes the rate design component.

(Source: P.A. 102-662, eff. 9-15-21.)

(220 ILCS 5/16-105.6)

Sec. 16-105.6. Amortization of charges or credits.

(a) It is in the public interest to mitigate the customer bill impacts of large expenses incurred by electric utilities by directing that expenses exceeding the applicable threshold specified in this Section be amortized over the prescribed period. Such amortization will levelize customer bill impacts and, in many instances, better align the period of cost recovery with the period over which customers receive the benefit of the expenditure. Accordingly, an electric utility that files a general rate increase under Section 9-201 of this Act or a Multi-Year Rate Plan under Section 16-108.18 of this Act shall amortize, over a 5-year period, each charge or credit that exceeds the applicable amount identified in subsection (b) of this Section and that relates to (1) a workforce reduction program's severance costs; (2) changes in accounting rules; (3) changes in law; (4) compliance with any Commission-initiated audit; and (5) a single storm or weather system, or other similar expense.

Any unamortized balance shall be reflected in rate base.

In this Section, "changes in law" includes any enactment, repeal, or amendment in a law, ordinance, rule, regulation, interpretation, permit, license, consent, or order, including those relating to taxes, accounting, or environmental matters, or in the interpretation or application thereof by any governmental authority occurring after the effective date of this amendatory Act of the 102nd General Assembly.

Nothing in this Section is intended to prohibit the Commission from reviewing the prudence and reasonableness of the costs amortized pursuant to this Section.

(b) An electric utility that serves more than 3,000,000 customers in the State shall amortize the full amount of each charge or credit described in subsection (a) of this Section that exceeds $10,000,000 in the applicable calendar year, and an electric utility that serves less than 3,000,000 customers in the State shall amortize the full amount of each such charge or credit that exceeds $3,700,000 in the applicable calendar year.

(Source: P.A. 102-662, eff. 9-15-21.)

(220 ILCS 5/16-105.7)

Sec. 16-105.7. Revenue balancing adjustments.

(a) It is in the public interest to decouple electric utility sales and revenues, to mitigate the impact on utilities of energy savings goals, to mitigate a utility's disincentive to promote energy efficiency, and to recognize changes in sales attributable to weather, electric vehicles and other electrification, adoption of distributed energy resources, and other volatile or uncontrollable factors without adversely affecting utility customers.

(b) For the purposes of this Section, "reconciliation period" means a period beginning with the January monthly billing period and extending through the December monthly billing period of the same calendar year.

(c) As set forth in subsection (d) of this Section, the Commission shall approve a tariff by which distribution revenues shall be compared annually to the revenue requirement or requirements approved by the Commission on which the rates giving rise to those revenues were based to prevent undercollections or overcollections. An electric utility shall submit an annual revenue balancing reconciliation report to the Commission reflecting the difference between the actual delivery service revenue and multi-year rate case revenue requirement for the applicable reconciliation and identifying the charges or credits to be applied thereafter. Such reconciliation and calculation of associated charges or credits shall be conducted on a customer class basis. The annual revenue balancing reconciliation report shall be filed with the Commission no later than March 20 of the year following a reconciliation period. The Commission may initiate a review of the revenue balancing reconciliation report each year to determine if any subsequent adjustment is necessary to align actual delivery service revenue and rate case revenue requirement. If the Commission elects to initiate such review, the Commission shall, after notice and hearing, enter an order approving, or approving as modified, such revenue balancing reconciliation report no later than 120 days after the utility files its report with the Commission. If the Commission does not initiate such a review, the revenue balancing reconciliation report and the identified charges or credits shall be deemed accepted and approved 120 days after the utility files the report and shall not be subject to review in any other proceeding. Any balancing adjustment shall take effect during the following January monthly billing period.

(d) Each electric utility shall file a tariff in compliance with the provisions of this Section within 120 days after the effective date of this amendatory Act of the 102nd General Assembly. The Commission shall approve the tariff if it finds that it is consistent with the provisions of the Section. If the Commission does not so find, it shall approve the tariff with modification to conform it to the requirements of this Section or otherwise reject the tariff and explain how the utility can modify the tariff and refile to comply with the requirements of this Section.

(Source: P.A. 102-662, eff. 9-15-21.)

(220 ILCS 5/16-105.10)

Sec. 16-105.10. Independent baseline assessment.

(a) Prior to the filing of the initial Multi-Year Integrated Grid Plan described in Section 16-105.17 of this Act, the General Assembly finds that an independent audit of the current state of the grid, and of the expenditures made since 2012, will need to be made.

Specifically, the General Assembly finds:

(1) Pursuant to the Energy Infrastructure Modernization Act and subsequent clarifying legislation, electric utilities in this State that serve over 300,000 retail customers have made substantial investments in the grid and advanced metering infrastructure.

(2) Before a Multi-Year Integrated Grid Plan is filed under Section 16-105.17, it is necessary to understand the benefits of these investments to the grid and to customers and to evaluate the current condition of the distribution grid.

(3) It is also necessary for electric utilities, the Commission, and stakeholders to have an independently verified set of data to establish the baseline for future distribution grid spending.

(4) The Commission has authority to order and implement the requirements of this Section under Section 8-102 of this Act.

(b) Terms used in this Section have the meanings given to those terms in Sections 16-102, 16-107.6, and 16-108 of this Act.

(c) Within 30 days after the effective date of this amendatory Act of the 102nd General Assembly, the Commission shall issue an order initiating an audit of each electric utility serving over 300,000 retail customers in the State, which shall examine the following:

(1) An assessment of the distribution grid, as described in paragraph (2) of subsection (a) of this Section. The Commission shall have the authority to require additional items which it deems necessary.

(2) An analysis of the utility's capital projects placed into service in the preceding 9 years, including, but not limited to, assessing the value of deploying advanced metering infrastructure to modernize and optimize the grid and deliver value to customers.

(3) An analysis of the utility's initiatives to optimize the reliability and resiliency of the grid, other than through capital spending.

(4) Creation of a data baseline to inform the beginning of the multi-year integrated grid planning process described in Section 16-105.17 of this Act.

(5) Identification of any deficiencies in data which may impact the planning process.

(d) It is contemplated that the auditor will utilize materials filed with the Commission by the utilities with respect to their expenditures in the preceding 9 years; however, the auditor may also, with Commission approval, assess other information deemed necessary to make its report.

(e) The results of the audit described in this Section shall be reflected in a report delivered to the Commission, describing the information specified in this Section. Such report is to be delivered no later than 180 days after the Commission enters its order pursuant to subsection (c) of this Section. It is understood that any public report may not contain items that are confidential or proprietary.

(f) The costs of an electric utility's audit described in this Section shall not exceed $500,000 and shall be paid for by the electric utility that is the subject of the audit. Such costs shall be a recoverable expense.

(g) The Commission shall have the authority to retain the services of an auditor to assist with the distribution planning process, as well as in docketed proceedings. Such expenses for these activities shall also be borne by the Commission.

(Source: P.A. 102-662, eff. 9-15-21.)

(220 ILCS 5/16-105.17)

Sec. 16-105.17. Multi-Year Integrated Grid Plan.

(a) The General Assembly finds that ensuring alignment of regulated utility operations, expenditures, and investments with public benefit goals, including safety, reliability, resiliency, affordability, equity, emissions reductions, and expansion of clean distributed energy resources, is critical to maximizing the benefits of the interconnected utility grid and cost-effective utility expenditures on the grid. It is the policy of the State to promote inclusive, comprehensive, transparent, cost-effective distribution system planning and disclosures processes that minimize long-term costs for Illinois customers and support the achievement of State renewable energy development and other clean energy, public health, and environmental policy goals. Utility distribution system expenditures, programs, investments, and policies must be evaluated in coordination with these goals. In particular, the General Assembly finds that:

(1) Investment in infrastructure to support and enable existing and new distributed energy resources creates significant economic development, environmental, and public health benefits in the State.

(2) Illinois' electricity distribution system must cost-effectively integrate renewable energy resources, including utility-scale renewable energy resources, community renewable generation, and distributed renewable energy resources, support beneficial electrification, including electric vehicle use and adoption, promote opportunities for third-party investment in nontraditional, grid-related technologies and resources such as batteries, solar photovoltaic panels, and smart thermostats, reduce energy usage generally and especially during times of greatest reliance on fossil fuels, and enhance customer engagement opportunities.

(3) Inclusive distribution system planning is an essential tool for the Commission, public utilities, and stakeholders to effectively coordinate environmental, consumer, reliability, and equity goals at fair and reasonable costs, and for ensuring transparent utility accountability for meeting those goals.

(4) Any planning process should advance Illinois energy policy goals while ensuring utility investments are cost-effective. Such a process should maximize the sharing of information, minimize overlap with existing filing requirements to ensure robust stakeholder participation, and recognize the responsibility of the utility to manage the grid in a safe, reliable manner.

(5) The General Assembly is concerned that, in the absence of a transparent, meaningful distribution system planning process, utility investments may not always serve customers' best interests, appropriately promote the expansion of clean distributed energy resources, and advance equity and environmental justice.

(6) The General Assembly is also encouraged by the opportunities presented by nontraditional solutions to utility, customer, and grid needs that may be more efficient and cost-effective, and less environmentally harmful than traditional solutions. Nontraditional solutions include distributed energy resources owned or implemented by customers and independent third parties, controllable load, beneficial electrification, or rate design that encourages efficient energy use.

(7) The General Assembly finds that Illinois utilities' current processes for planning their distribution system should be made more accessible and transparent to individuals and communities, and that more inclusive and accessible distribution system planning processes would be in the interests of all Illinois residents.

(8) The General Assembly finds it would be beneficial to require utilities to demonstrate how their spending promotes identified State clean energy goals, such as integrating renewable energy, empowering customers to make informed choices, supporting electric vehicles, beneficial electrification, and energy storage, achieving equity goals, enhancing resilience, and maintaining reliability.

The General Assembly therefore directs the utilities to implement distribution system planning as described in this Section in order to accelerate progress on Illinois clean energy and environmental goals and hold electric utilities publicly accountable for their performance.

(b) Unless otherwise specified, the terms used in this Section shall have the same meanings as defined in Sections 16-102 and 16-107.6. As used in this Section:

"Demand response" means measures that decrease peak electricity demand or shift demand from peak to off-peak periods.

"Distributed energy resources" or "DER" means a wide range of technologies that are connected to the grid, including those that are located on the customer side of the customer's electric meter and can provide value to the distribution system, including, but not limited to, distributed generation, energy storage, electric vehicles, and demand response technologies.

"Environmental justice communities" means the definition of that term based on existing methodologies and findings, used and as may be updated by the Illinois Power Agency and its Program Administrator in the Illinois Solar for All Program.

(c) This Section applies to electric utilities serving more than 500,000 retail customers in the State.

(d) The Multi-Year Integrated Grid Plan ("the Plan") shall be designed to:

(1) ensure coordination of the State's renewable energy goals, climate and environmental goals with the utility's distribution system investments, and programs and policies over a 5-year planning horizon to maximize the benefits of each while ensuring utility expenditures are cost-effective;

(2) optimize utilization of electricity grid assets and resources to minimize total system costs;

(3) support efforts to bring the benefits of grid modernization and clean energy, including, but not limited to, deployment of distributed energy resources, to all retail customers, and support efforts to bring at least 40% of the benefits of those benefits to Equity Investment Eligible Communities. Nothing in this paragraph is meant to require a specific amount of spending in a particular geographic area;

(4) enable greater customer engagement, empowerment, and options for energy services;

(5) reduce grid congestion, minimize the time and expense associated with interconnection, and increase the capacity of the distribution grid to host increasing levels of distributed energy resources, to facilitate availability and development of distributed energy resources, particularly in locations that enhance consumer and environmental benefits;

(6) ensure opportunities for robust public participation through open, transparent planning processes.

(7) provide for the analysis of the cost-effectiveness of proposed system investments, which takes into account environmental costs and benefits;

(8) to the maximum extent practicable, achieve or support the achievement of Illinois environmental goals, including those described in Section 9.10 of the Environmental Protection Act and Section 1-75 of the Illinois Power Agency Act, and emissions reductions required to improve the health, safety, and prosperity of all Illinois residents;

(9) support existing Illinois policy goals promoting the long-term growth of energy efficiency, demand response, and investments in renewable energy resources;

(10) provide sufficient public information to the Commission, stakeholders, and market participants in order to enable nonemitting customer-owned or third-party distributed energy resources, acting individually or in aggregate, to seamlessly and easily connect to the grid, provide grid benefits, support grid services, and achieve environmental outcomes, without necessarily requiring utility ownership or controlling interest over those resources, and enable those resources to act as alternatives to utility capital investments; and

(11) provide delivery services at rates that are affordable to all customers, including low-income customers.

(e) Plan Development Stakeholder Process.

(1) To promote the transparency of utility distributions system planned investments and the planning process for those investments, the Commission shall convene a workshop process, over a period of no less than 5 months, for each such utility for the purpose of establishing an open, inclusive, and cooperative forum regarding such investments. The workshops shall be facilitated by an independent, third-party facilitator selected by the Commission. Data and projections provided through the workshop process shall be designed to provide participants with information about the electric utility's (i) historic distribution system investments for at least the 5 years prior to the year in which the workshop is held and (ii) planned investments for the 5-year period following the year in which the workshop is held. The workshop process shall recognize that estimates for later years will be less reliable and indicative of future conduct than estimates for earlier years and that the electric utility is subject to financial and system planning processes. No later than January 1, 2022, the facilitator shall initiate a series of workshops for each electric utility subject to this Section. The series of workshops shall include no fewer than 6 workshops and shall conclude no later than June 1, 2022.

(2) The workshops shall be designed to achieve the following objectives:

(A) review utilities' planned capital investments and supporting data;

(B) review how utilities plan to invest in their distribution system in order to meet the system's projected needs;

(C) review system and locational data on reliability, resiliency, DER, and service quality provided by the utilities;

(D) solicit and consider input from diverse stakeholders, including representatives from environmental justice communities, geographically diverse communities, low-income representatives, consumer representatives, environmental representatives, organized labor representatives, third-party technology providers, and utilities;

(E) consider proposals from utilities and stakeholders on programs and policies necessary to achieve the objectives in subsection (d) of this Section;

(F) consider proposals applicable to each component of the utilities' Multi-Year Integrated Grid Plan filings under paragraph (2) of subsection (f) of this Section;

(G) educate and equip interested stakeholders so that they can effectively and efficiently provide feedback and input to the electric utility; and

(H) review planned capital investment to ensure that delivery services are provided at rates that are affordable to all customers, including low-income customers.

(3) To the extent any of the information in subparagraphs (A) through (H) of paragraph (2) of this subsection is designated as confidential and proprietary under the Commission's rules, the proponent of the designation shall have the burden of making the requisite showing under the Commission's rules. For data that is determined to be confidential or that includes personally identifiable information, the Commission may develop procedures and processes to enable data sharing with parties and stakeholders while ensuring the confidentiality of the information.

(4) Workshops should be organized and facilitated in a manner that encourages representation from diverse stakeholders, ensuring equitable opportunities for participation, without requiring formal intervention or representation by an attorney. Workshops should be held during both day and evening hours, in a variety of locations within each electric utility's service territory, and should allow remote participation.

(5) It is a goal of the State that this workshop process will provide a forum for interested stakeholders to effectively and efficiently provide feedback and input to the electric utility. It is also a goal of the State that stakeholder participation in this process will prepare stakeholders to more capably participate in Multi-Year Rate Plan proceedings conducted pursuant to Section 16-108.18 of this Act, if they so elect. As part of the workshop process, the electric utility shall submit to the Commission the electric utility's capital investments proposal, and supporting data described in subparagraphs (A) through (C) of paragraph (2) of this subsection (e) before the start of workshops to allow interested stakeholders to reasonably review data before attending workshops. The Commission shall make public the utility capital investments proposal by posting it on the Commission's website and set the location and time of any workshop to be held as part of the workshop process, and establish a data request process, consistent with the Commission's rules, that affords workshop participants opportunities to submit data requests to the utility, and receive responses in accordance with the utility's obligations under the law, prior to the workshop, regarding the information described in this paragraph (5). Upon the written request of a workshop participant, the utility shall also present at a given workshop at least one appropriate company representative who can address the specific written questions or written categories of questions identified in advance by the workshop participant regarding issues related to the utility's Multi-Year Integrated Grid Plan. To facilitate public feedback, the administrator facilitating the workshops shall, throughout the workshop process, develop questions for stakeholder input on topics being considered. This may include, but is not limited to: design of the workshop process, locational data and information provided by utilities, alignment of plans, programs, investments and objectives, and other topics as deemed appropriate by the Commission facilitation staff. Stakeholder feedback shall not be limited to these questions. The information provided as part of the workshop process pursuant to this subsection (e) is intended to be informational and to provide a preliminary view of costs and investments, which may change. Accordingly, the information provided pursuant to this subsection (e) shall not be binding on the utility and shall not be the sole basis for a finding in any Commission proceeding of imprudence, unreasonableness, or lack of use or usefulness of any individual or aggregate level of utility plant or other investment or expenditure addressed; however, information contained in the plan may be used in a proceeding before the Commission, with weight of such evidence to be determined by the Commission.

(6) Workshops shall not be considered settlement negotiations, compromise negotiations, or offers to compromise for the purposes of Illinois Rule of Evidence 408. All materials shared as a part of the workshop process, and that are not determined to be confidential as described in paragraph (3) of this subsection (e), shall be made publicly available on a website made available by the Commission.

(7) On conclusion of the workshops, the Commission shall open a comment period that allows interested and diverse stakeholders to submit comments and recommendations regarding the utility's Multi-Year Integrated Grid Plan filing. Based on the workshop process and stakeholder comments and recommendations offered verbally or in writing during the workshops and in writing during the comment period following the workshops, the independent third-party facilitator shall prepare a report, to be submitted to the Commission no later than July 1, 2022, describing the stakeholders, discussions, proposals, and areas of consensus and disagreement from the workshop process, and making recommendations to the Commission regarding the utility's Multi-Year Integrated Grid Plan. Interested stakeholders shall have an opportunity to provide comment on the independent third-party facilitator report.

(8) Based on discussions in the workshops, the independent third-party facilitator report, and stakeholder comments and recommendations made during and following the workshop process, the Commission shall issue initiating orders no later than August 1, 2022, requiring the electric utilities subject to this Section to file the first Multi-Year Integrated Grid Plan no later than January 20, 2023. The initiating orders shall specify the requirements applicable to the utilities' Multi-Year Integrated Grid Plans, which shall supplement and not replace those requirements described in subsection (f) of this Section.

(f) Multi-Year Integrated Grid Plan.

(1) Pursuant to this subsection (f) and the initiating orders of the Commission, each electric utility subject to this Section shall, no later than January 20, 2023, submit its first Multi-Year Integrated Grid Plan. No later than January 20, 2026, and every 4 years thereafter, the utility shall submit its subsequent Plan. Each Plan shall:

(A) incorporate requirements established by the Commission in its initiating order; and

(B) propose distribution system investment programs, policies, and plans designed to optimize achievement of the objectives set forth in subsection (d) of this Section and achieve the metrics approved by the Commission pursuant to Section 16-108.18 of this Act.

To the extent practicable and reasonable, all programs, policies, and initiatives proposed by the utility in its plan should be informed by stakeholder input received during the workshop process pursuant to subsection (e) of this Section. Where specific stakeholder input has not been incorporated in proposed programs, policies, and plans, the electric utility shall provide an explanation as to why that input was not incorporated.

(2) In order to ensure electric utilities' ability to meet the goals and objectives set forth in this Section, the Multi-Year Integrated Grid Plans must include, at minimum, the following information:

(A) A description of the utility's distribution system planning process, including:

(i) the overview of the process, including frequency and duration of the process, roles, and responsibilities of utility personnel and departments involved;

(ii) a summary of the meetings with stakeholders conducted prior to filing of the plan with the Commission.

(iii) the description of any coordination of the processes with any other planning process internal or external to the utility, including those required by a regional transmission operator.

(B) A detailed description of the current operating conditions for the distribution system separately presented for each of the utility's operating areas, where possible, including a detailed description, with supporting data, of system conditions, including baseline data regarding the utility's distribution system from the utility's annual report to the Commission, total distribution system substation capacity in kVa, total miles of primary overhead distribution wire, and total miles of primary underground distribution cable, distributed energy resource deployment by type, size, customer class, and geographic dispersion as to those DERs that have completed the interconnection process, the most current distribution line loss study, current and expected System Average Interruption Frequency Index and Customer Average Interruption Duration Index data for the system, identification of the system model software currently used and planned software deployments, and other data needs as requested by the Commission or as determined through Commission rules. The description shall also include the utility's most recent system load and peak demand forecast for at least the next 5 years, and up to 10 years if available, a discussion of how the forecast was prepared and how distributed energy resources and energy efficiency were factored into the forecast, and identification of the forecasting software currently used and planned software deployments.

(C) Financial Data.

(i) For each of the preceding 5 years, the utility's distribution system investments by the investment categories tracked by the utility, including, but not limited to, new business, facility relocation, capacity expansion, system performance, preventive maintenance, corrective maintenance, the total amount of investments associated with the integration of DERs, the total amount of charges to DER developers and retail customers for interconnection of DERs to the distribution system, and a list of each major investment category the utility used to maintain its routine standing operational activities and the associated plant in service amount for each category in which the plant in service amount is at least $2,000,000;

(ii) For each of the preceding 5 years, data on and a discussion of the utility's distribution system operation and maintenance expenses;

(iii) A 5-year long-range forecast of distribution system capital investments and operational and maintenance expenses, including a discussion of any projections for expenses for the categories listed in subparagraph (i) of this item (C).

(D) System data on DERs on the utility's distribution system, including the total number and nameplate capacity of DERs that completed interconnection in the prior year, current DER deployment by type, size, and geographic dispersion, to the extent that granular geographic information does not disclose personally identifiable information, and other data as requested by the Commission or determined by Commission rules.

(E) Hosting Capacity and Interconnection Requirements.

(i) The utility shall make available on its website the hosting capacity analysis results that shall include mapping and GIS capability, as well as any other requirements requested by the Commission or determined through Commission rules. The plan shall identify where the hosting capacity analysis results shall be made publicly available. This shall also include an assessment of the impact of utility investments over the next 5 years on hosting capacity and a narrative discussion of how the hosting capacity analysis advances customer-sited distributed energy resources, including electric vehicles, energy storage systems, and photovoltaic resources, and how the identification of interconnection points on the distribution system will support the continued development of distributed energy resources.

(ii) Discussion of the utility's interconnection requirements and how they comply with the Commission's applicable regulations.

(F) Identification and discussion of the scenarios considered in the development of the utility's Multi-Year Integrated Grid Plan, including DER scenarios, and discussion of base-case and alternative scenarios, how the scenarios were developed and selected, and how the scenarios include a reasonable mix of DERs scenarios, types, and geographic dispersion. Scenarios shall at least consider the 5-year forecast horizon of the Multi-Year Integrated Grid Plan, but may also consider longer-term scenarios where data is available. The plan shall also include requirements requested by the Commission or determined through Commission rules.

(G) An evaluation of the short-term and long-run benefits and costs of distributed energy resources located on the distribution system, including, but not limited to, the locational, temporal, and performance-based benefits and costs of distributed energy resources. The utility shall use the results of this evaluation to inform its analysis of Solution Sourcing Opportunities, including nonwires alternatives, under subparagraph (K) of paragraph (2) subsection (f) of this Section. The Commission may use the data produced through this evaluation to, among other use-cases, inform the Commission's investigation and establishment of tariffs and compensation for distributed energy resources interconnecting to the utility's distribution system, including rebates provided by the electric utility pursuant to Section 16-107.6 of this Act.

(H) Long-term Distribution System Investment Plan.

(i) The utility's planned distribution capital investments for the period covered by the planning process required by this Section, by the investment categories used by the utility, and with discussion of any individual planned projects with a planned total investment gross amount of $3,000,000 or more and of the alternatives considered by the utility to such individual projects including any non-traditional alternatives and DER alternatives, and supporting data. This shall provide sufficiently detailed explanations of how the planned investments shall support the goals in subsection (d) of this Section.

(ii) Discussion of how the utility's capital investments plan is consistent with Commission orders regarding the procurement of renewable resources as discussed in Section 16-111.5 of this Act, energy efficiency plans as discussed in Section 8-103B, distributed generation rebates as discussed in Section 16-107.6, and any other Commission order affecting the goals described in subsection (d) of this Section.

(iii) A plan for achieving the applicable metrics that were approved by the Commission for the utility pursuant to subsection (e) of Section 16-108.18 of this Act.

(iv) A narrative discussion of the utility's vision for the distribution system over the next 5 years.

(v) Any additional information requested by the Commission or determined through Commission rules.

(I) A detailed description of historic distribution system operations and maintenance expenditures for the preceding 5 years and of planned or projected operations and maintenance expenditures for the period covered by the planning process required by this Section, as well as the data, reasoning and explanation supporting planned or projected expenditures. Any additional information requested by the Commission or determined through Commission rules.

(J) A detailed plan for achieving the applicable metrics that were approved by the Commission for the utility pursuant to subsection (e) of Section 16-108.18 of this Act, including, but not limited to, the following:

(i) A description of, exclusive of low-income rate relief programs and other income-qualified programs, how the utility is supporting efforts to bring 40% of benefits from programs, policies, and initiatives proposed in their Multi-Year Integrated Grid Plan to ratepayers in low-income and environmental justice communities. This shall also include any information requested by the Commission or determined through Commission rules. Nothing in this subparagraph is meant to require a specific amount of spending in a particular geographic area.

(ii) A detailed analysis of current and projected flexible resources, including resource type, size (in MW and MWh), location and environmental impact, as well as anticipated needs that can be met using flexible resources, to meet the goals described in subsection (d) of this Section, to meet the applicable metrics that were approved by the Commission for the utility pursuant to subsection (e) of Section 16-108.18 of this Act, and any other Commission order affecting the goals described in subsection (d) of this Section.

(iii) Any additional information requested by the Commission or determined through Commission rules.

(K) Identification of potential cost-effective solutions from nontraditional and third-party owned investments that could meet anticipated grid needs, including, but not limited to, distributed energy resources procurements, tariffs or contracts, programmatic solutions, rate design options, technologies or programs that facilitate load flexibility, nonwires alternatives, and other solutions that are intended to meet the objectives described at subsection (d). It is the policy of this State that cost-effective third-party or customer-owned distributed energy resources create robust competition and customer choice and shall be considered as appropriate. The Commission shall establish rules determining data or methods for Solution Sourcing Opportunities.

(L) A detailed description of the utility's interoperability plan, which must describe the manner in which the electric utility's current and planned distribution system investments will work together and exchange information and data, the extent to which the utility is implementing open standards and interfaces with third-party distributed energy resource owners and aggregators, and the utility's plan for interoperability testing and certification.

(3) To the extent any information in utilities' Multi-Year Integrated Grid Plans is designated as confidential and proprietary under the Commission's rules, the proponent of the designation shall have the burden of making the requisite showing under the Commission's rules. For data that is determined to be confidential or that includes personally identifiable information, the Commission may develop procedures and processes to enable data sharing with parties and stakeholders while ensuring the confidentiality of the information. All confidential information exchanged, submitted, or shared by a utility pursuant to this Section shall be protected from intentional and accidental dissemination. The Commission shall have authority to supervise, protect, and restrict access to all confidential, commercially sensitive, or system security related information and data, and shall be authorized to take all necessary steps to protect that information from unauthorized disclosure. This paragraph shall not be interpreted to require a utility to make publicly available any information or data that could compromise the physical or cyber security of a utility's distribution system. Any party that accidentally disseminates confidential information obtained pursuant to a proceeding initiated in accordance with this Section, or is the victim of a cyber-security breach, must notify the affected utility, the Illinois Attorney General, and the Commission staff with 24 hours of knowledge of such dissemination or breach. Any party that fails to provide required notification of such a breach shall be subject to remedies available to the Commission and the Illinois Attorney General.

(4) It is the policy of this State that holistic consideration of all related investments, planning processes, tariffs, rate design options, programs, and other utility policies and plans shall be required. To that end, the Commission shall consider, comprehensively, the impact of all related plans, tariffs, programs, and policies on the Plan and on each other, including:

(A) time-of-use pricing program pursuant to Section 16-107.7 of this Act, hourly pricing program pursuant to Section 16-107 of this Act, and any other time-variant or dynamic pricing program;

(B) distributed generation rebate pursuant to Section 16-107.6 of this Act;

(C) net electricity metering, pursuant to Section 16-107.5 of this Act;

(D) energy efficiency programs pursuant to Section 8-103B of this Act;

(E) beneficial electrification programs pursuant to Section 16-107.8 of this Act;

(F) Equitable Energy Upgrade Program pursuant to Section 16-111.10 of this Act;

(G) renewable energy programs and procurements set forth in the Illinois Power Agency Act, including, but not limited to, those set forth in the long-term renewable resources procurement plan developed pursuant to Section 1-20 of that Act; and

(H) other plans, programs, and policies that are relevant to distribution grid investments, costs, planning, and other categories as requested by the Commission.

The Plan shall comprehensively detail the relationship between these plans, tariffs, and programs and to the electric utility's achievement of the objectives in subsection (d). The Plan shall be designed to coordinate each of these plans, programs, and tariffs with the electric utility's long-term distribution system investment planning in order to maximize the benefits of each.

(5) The initiating order for the initial Multi-Year Integrated Grid Plan, as well as each electric utility's subsequent Integrated Grid Plans under subsection (g), shall begin a contested proceeding as described in subsection (d) of Section 10-101.1 of this Act.

(A) In evaluating a utility's Plan, the Commission shall consider, at minimum, whether the Plan:

(1) meets the objectives of this Section;

(2) includes the components in paragraph (2) of subsection (f) of this Section;

(3) considers and incorporates, where practicable, input from interested stakeholders, including parties and people who offer public comment without legal representation;

(4) considers nontraditional, including third-party owned, investment alternatives that can meet grid needs and provide additional benefits (including consumer, economic, and environmental benefits) beyond comparable, traditional utility-planned capital investments;

(5) equitably benefits environmental justice communities; and

(6) maximizes consumer, environmental, economic, and community benefits over a 10-year horizon.

(B) The Commission, after notice and hearing, shall modify each electric utility's Plan as necessary to comply with the objectives of this Section. The Commission may approve, or modify and approve, a Plan only if it finds that the Plan is reasonable, complies with the objectives and requirements of this Section, and reasonably incorporates input from parties. The Commission may reject each electric utility's Plan if it finds that the Plan does not comply with the objectives and requirements of this Section. If the Commission enters an order rejecting a Plan, the utility must refile a Plan within 3 months after that order, and until the Commission approves a Plan, the utility's existing Plan will remain in effect.

(C) For the initial Integrated Grid Plan filings, the Commission shall enter an order approving, modifying, or rejecting the Plan no later than December 15, 2023. For subsequent Integrated Grid Plan filings, the Commission shall enter an order approving, modifying, or rejecting the Plan no later than December 15 of the year in which it was filed.

(D) Each electric utility shall file its proposed Initial Multi-Year Integrated Grid Plan no later than January 20, 2023. Prior to that date and following the initiating order, the Commission shall initiate a case management conference and shall take any appropriate steps to begin meaningful consideration of issues, including enabling interested parties to begin conducting discovery.

(6) As part of its order approving a utility's Multi-Year Integrated Grid Plan, including any modifications required, the Commission may create a subsequent implementation plan docket, or multiple implementation plan dockets, if the Commission determines that multiple dockets would be preferable, to consider a utility's detailed plan or plans, as directed in the Commission's order.

(g) No later than January 20, 2026 and every 4 years thereafter, each electric utility subject to this Section shall file a new Multi-Year Integrated Grid Plan for the subsequent 4 delivery years after the completion of the then-effective Plan. Each Plan shall meet the requirements described in subsection (f) of this Section, and shall be preceded by a workshop process which meets the same requirements described in subsection (e). If appropriate, the Commission may require additional implementation dockets to follow Subsequent Multi-Year Integrated Grid Plan filings.

(h) During the period leading to approval of the first Multi-Year Integrated Grid Plan, each electric utility will necessarily continue to invest in its distribution grid. Those investments will be subject to a determination of prudence and reasonableness consistent with Commission practice and law. Any failure of such investments to conform to the Multi-Year Integrated Grid Plan ultimately approved shall not imply imprudence or unreasonableness.

(i) The Commission shall adopt rules to carry out the provisions of this Section under the emergency rulemaking provisions set forth in Section 5-45 of the Illinois Administrative Procedure Act, and such emergency rules may be effective no later than 90 days after the effective date of this amendatory Act of the 102nd General Assembly.

(Source: P.A. 102-662, eff. 9-15-21.)

(220 ILCS 5/16-106)

Sec. 16-106. Billing experiments. During the mandatory transition period, an electric utility may at its discretion conduct one or more experiments for the provision or billing of services on a consolidated or aggregated basis, for the provision of real-time pricing, or other billing or pricing experiments, and may include experimental programs offered to groups of retail customers possessing common attributes as defined by the electric utility, such as the members of an organization that was established to serve a well-defined industry group, companies having multiple sites, or closely located or affiliated buildings, provided that such groups exist for a purpose other than obtaining energy services and have been in existence for at least 10 years. The offering of such a program by an electric utility to retail customers participating in the program, and the participation by those customers in the program, shall not create any right in any other retail customer or group of customers to participate in the same or a similar program. The Commission shall allow such experiments to go into effect upon the filing by the electric utility of a statement describing the program. Nothing contained in this Section shall be deemed to prohibit the electric utility from offering, or the Commission from approving, experimental rates, tariffs and services in addition to those allowed under this Section. The Commission shall review and report annually the progress, participation and effects of such experiments to the General Assembly. Based upon its review, recommendations for modification of such experiments may be made by the Commission to the Illinois General Assembly.

(Source: P.A. 90-561, eff. 12-16-97.)

(220 ILCS 5/16-107)

Sec. 16-107. Real-time pricing.

(a) Each electric utility shall file, on or before May 1, 1998, a tariff or tariffs which allow nonresidential retail customers in the electric utility's service area to elect real-time pricing beginning October 1, 1998.

(b) Each electric utility shall file, on or before May 1, 2000, a tariff or tariffs which allow residential retail customers in the electric utility's service area to elect real-time pricing beginning October 1, 2000.

(b-5) Each electric utility shall file a tariff or tariffs allowing residential retail customers in the electric utility's service area to elect real-time pricing beginning January 2, 2007. The Commission may, after notice and hearing, approve the tariff or tariffs. A tariff or tariffs approved pursuant to this subsection (b-5) shall, at a minimum, describe (i) the methodology for determining the market price of energy to be reflected in the real-time rate and (ii) the manner in which customers who elect real-time pricing will be provided with ready access to hourly market prices, including, but not limited to, day-ahead hourly energy prices. A customer who elects real-time pricing under a tariff approved under this subsection (b-5) and thereafter terminates the election shall not return to taking service under the tariff for a period of 12 months following the date on which the customer terminated real-time pricing. However, this limitation shall cease to apply on such date that the provision of electric power and energy is declared competitive under Section 16-113 of this Act for the customer group or groups to which this subsection (b-5) applies.

A proceeding under this subsection (b-5) may not exceed 120 days in length.

(b-10) Each electric utility providing real-time pricing pursuant to subsection (b-5) shall install a meter capable of recording hourly interval energy use at the service location of each customer that elects real-time pricing pursuant to this subsection.

(b-15) If the Commission issues an order pursuant to subsection (b-5), the affected electric utility shall contract with an entity not affiliated with the electric utility to serve as a program administrator to develop and implement a program to provide consumer outreach, enrollment, and education concerning real-time pricing and to establish and administer an information system and technical and other customer assistance that is necessary to enable customers to manage electricity use. The program administrator: (i) shall be selected and compensated by the electric utility, subject to Commission approval; (ii) shall have demonstrated technical and managerial competence in the development and administration of demand management programs; and (iii) may develop and implement risk management, energy efficiency, and other services related to energy use management for which the program administrator shall be compensated by participants in the program receiving such services. The electric utility shall provide the program administrator with all information and assistance necessary to perform the program administrator's duties, including, but not limited to, customer, account, and energy use data. The electric utility shall permit the program administrator to include inserts in residential customer bills 2 times per year to assist with customer outreach and enrollment.

The program administrator shall submit an annual report to the electric utility no later than April 1 of each year describing the operation and results of the program, including information concerning the number and types of customers using real-time pricing, changes in customers' energy use patterns, an assessment of the value of the program to both participants and non-participants, and recommendations concerning modification of the program and the tariff or tariffs filed under subsection (b-5). This report shall be filed by the electric utility with the Commission within 30 days of receipt and shall be available to the public on the Commission's web site.

(b-20) The Commission shall monitor the performance of programs established pursuant to subsection (b-15) and shall order the termination or modification of a program if it determines that the program is not, after a reasonable period of time for development not to exceed 4 years, resulting in net benefits to the residential customers of the electric utility.

(b-25) An electric utility shall be entitled to recover reasonable costs incurred in complying with this Section, provided that recovery of the costs is fairly apportioned among its residential customers as provided in this subsection (b-25). The electric utility may apportion costs on the residential customers who elect real-time pricing, but may also impose some of the costs of real-time pricing on customers who do not elect real-time pricing.

(c) The electric utility's tariff or tariffs filed pursuant to this Section shall be subject to Article IX.

(d) This Section does not apply to any electric utility providing service to 100,000 or fewer customers.

(Source: P.A. 99-906, eff. 6-1-17.)