(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.
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(2) Illinois' electricity distribution system must
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| 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.
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(3) Inclusive distribution system planning is an
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| 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.
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(4) Any planning process should advance Illinois
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| 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.
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(5) The General Assembly is concerned that, in the
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| 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.
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(6) The General Assembly is also encouraged by the
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| 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.
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(7) The General Assembly finds that Illinois
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| 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.
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(8) The General Assembly finds it would be beneficial
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| 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.
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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
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| 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;
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(2) optimize utilization of electricity grid assets
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| and resources to minimize total system costs;
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(3) support efforts to bring the benefits of grid
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| 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;
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(4) enable greater customer engagement, empowerment,
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| and options for energy services;
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(5) reduce grid congestion, minimize the time and
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| 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;
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(6) ensure opportunities for robust public
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| participation through open, transparent planning processes.
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(7) provide for the analysis of the
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| cost-effectiveness of proposed system investments, which takes into account environmental costs and benefits;
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(8) to the maximum extent practicable, achieve or
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| 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;
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(9) support existing Illinois policy goals promoting
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| the long-term growth of energy efficiency, demand response, and investments in renewable energy resources;
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(10) provide sufficient public information to the
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| 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
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(11) provide delivery services at rates that are
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| affordable to all customers, including low-income customers.
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(e) Plan Development Stakeholder Process.
(1) To promote the transparency of utility
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| 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.
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(2) The workshops shall be designed to achieve the
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(A) review utilities' planned capital investments
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(B) review how utilities plan to invest in their
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| distribution system in order to meet the system's projected needs;
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(C) review system and locational data on
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| reliability, resiliency, DER, and service quality provided by the utilities;
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(D) solicit and consider input from diverse
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| 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;
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(E) consider proposals from utilities and
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| stakeholders on programs and policies necessary to achieve the objectives in subsection (d) of this Section;
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(F) consider proposals applicable to each
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| component of the utilities' Multi-Year Integrated Grid Plan filings under paragraph (2) of subsection (f) of this Section;
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(G) educate and equip interested stakeholders so
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| that they can effectively and efficiently provide feedback and input to the electric utility; and
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(H) review planned capital investment to ensure
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| that delivery services are provided at rates that are affordable to all customers, including low-income customers.
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(3) To the extent any of the information in
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| 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.
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(4) Workshops should be organized and facilitated in
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| 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.
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(5) It is a goal of the State that this workshop
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| 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.
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(6) Workshops shall not be considered settlement
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| 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.
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(7) On conclusion of the workshops, the Commission
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| 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.
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(8) Based on discussions in the workshops, the
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| 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.
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(f) Multi-Year Integrated Grid Plan.
(1) Pursuant to this subsection (f) and the
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| 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:
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(A) incorporate requirements established by the
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| Commission in its initiating order; and
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(B) propose distribution system investment
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| 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.
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To the extent practicable and reasonable, all
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| 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.
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(2) In order to ensure electric utilities' ability to
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| meet the goals and objectives set forth in this Section, the Multi-Year Integrated Grid Plans must include, at minimum, the following information:
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(A) A description of the utility's distribution
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| system planning process, including:
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(i) the overview of the process, including
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| frequency and duration of the process, roles, and responsibilities of utility personnel and departments involved;
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(ii) a summary of the meetings with
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| stakeholders conducted prior to filing of the plan with the Commission.
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(iii) the description of any coordination of
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| the processes with any other planning process internal or external to the utility, including those required by a regional transmission operator.
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(B) A detailed description of the current
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| 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.
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(C) Financial Data.
(i) For each of the preceding 5 years, the
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| 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;
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(ii) For each of the preceding 5 years, data
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| on and a discussion of the utility's distribution system operation and maintenance expenses;
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(iii) A 5-year long-range forecast of
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| 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).
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(D) System data on DERs on the utility's
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| 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.
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(E) Hosting Capacity and Interconnection
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(i) The utility shall make available on its
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| 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.
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(ii) Discussion of the utility's
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| interconnection requirements and how they comply with the Commission's applicable regulations.
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(F) Identification and discussion of the
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| 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.
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(G) An evaluation of the short-term and long-run
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| 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.
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(H) Long-term Distribution System Investment Plan.
(i) The utility's planned distribution
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| 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.
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(ii) Discussion of how the utility's capital
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| 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.
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(iii) A plan for achieving the applicable
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| metrics that were approved by the Commission for the utility pursuant to subsection (e) of Section 16-108.18 of this Act.
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(iv) A narrative discussion of the utility's
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| vision for the distribution system over the next 5 years.
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(v) Any additional information requested by
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| the Commission or determined through Commission rules.
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(I) A detailed description of historic
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| 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.
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(J) A detailed plan for achieving the applicable
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| 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:
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(i) A description of, exclusive of low-income
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| 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.
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(ii) A detailed analysis of current and
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| 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.
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(iii) Any additional information requested by
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| the Commission or determined through Commission rules.
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(K) Identification of potential cost-effective
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| 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.
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(L) A detailed description of the utility's
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| 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.
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(3) To the extent any information in utilities'
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| 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.
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(4) It is the policy of this State that holistic
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| 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:
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(A) time-of-use pricing program pursuant to
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| 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;
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(B) distributed generation rebate pursuant to
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| Section 16-107.6 of this Act;
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(C) net electricity metering, pursuant to Section
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(D) energy efficiency programs pursuant to
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| Section 8-103B of this Act;
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(E) beneficial electrification programs pursuant
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| to Section 16-107.8 of this Act;
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(F) Equitable Energy Upgrade Program pursuant to
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| Section 16-111.10 of this Act;
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(G) renewable energy programs and procurements
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| 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
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(H) other plans, programs, and policies that are
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| relevant to distribution grid investments, costs, planning, and other categories as requested by the Commission.
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The Plan shall comprehensively detail the
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| 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.
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(5) The initiating order for the initial Multi-Year
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| 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.
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(A) In evaluating a utility's Plan, the
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| Commission shall consider, at minimum, whether the Plan:
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(1) meets the objectives of this Section;
(2) includes the components in paragraph (2)
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| of subsection (f) of this Section;
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(3) considers and incorporates, where
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| practicable, input from interested stakeholders, including parties and people who offer public comment without legal representation;
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(4) considers nontraditional, including
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| 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;
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(5) equitably benefits environmental justice
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(6) maximizes consumer, environmental,
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| economic, and community benefits over a 10-year horizon.
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(B) The Commission, after notice and hearing,
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| 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.
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(C) For the initial Integrated Grid Plan filings,
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| 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.
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(D) Each electric utility shall file its proposed
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| 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.
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(6) As part of its order approving a utility's
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| 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.
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(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.)
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(220 ILCS 5/16-107.5)
Sec. 16-107.5. Net electricity metering. (a) The General Assembly finds and declares that a program to provide net electricity
metering, as defined in this Section,
for eligible customers can encourage private investment in renewable energy
resources, stimulate
economic growth, enhance the continued diversification of Illinois' energy
resource mix, and protect
the Illinois environment. Further, to achieve the goals of this Act that robust options
for customer-site distributed generation continue to thrive in
Illinois, the General Assembly finds that a predictable
transition must be ensured for customers between full net
metering at the retail electricity rate to the distribution
generation rebate described in Section 16-107.6.
(b) As used in this Section, (i) "community renewable generation project" shall have the meaning set forth in Section 1-10 of the Illinois Power Agency Act; (ii) "eligible customer" means a retail
customer that owns, hosts, or operates, including any third-party owned systems, a
solar, wind, or other eligible renewable electrical generating facility that is
located on the customer's premises or customer's side of the billing meter and is intended primarily to offset the customer's
own current or
future electrical requirements; (iii) "electricity provider" means an electric utility or alternative retail electric supplier; (iv) "eligible renewable electrical generating facility" means a generator, which may include the co-location
of an energy storage system, that is interconnected under rules adopted by the Commission and is powered by solar electric energy, wind, dedicated crops grown for electricity generation, agricultural residues, untreated and unadulterated wood waste, livestock manure, anaerobic digestion of livestock or food processing waste, fuel cells or microturbines powered by renewable fuels, or hydroelectric energy; (v) "net electricity metering" (or "net metering") means the
measurement, during the
billing period applicable to an eligible customer, of the net amount of
electricity supplied by an
electricity provider to the customer or provided to the electricity provider by the customer or subscriber; (vi) "subscriber" shall have the meaning as set forth in Section 1-10 of the Illinois Power Agency Act; (vii) "subscription" shall have the meaning set forth in Section 1-10 of the Illinois Power Agency Act; (viii) "energy
storage system" means commercially available technology that
is capable of absorbing energy and storing it for a period of
time for use at a later time, including, but not limited to,
electrochemical, thermal, and electromechanical technologies,
and may be interconnected behind the customer's meter or
interconnected behind its own meter; and (ix) "future
electrical requirements" means modeled electrical requirements upon occupation of a new or vacant property, and other reasonable expectations of future electrical use, as well as, for occupied properties, a reasonable approximation of the annual load of 2 electric vehicles and, for non-electric heating customers, a reasonable approximation of the
incremental electric load associated with fuel switching. The
approximations shall be applied to the appropriate net
metering tariff and do not need to be unique to each
individual eligible customer. The utility shall submit these
approximations to the Commission for review, modification, and
approval.
(c) A net metering facility shall be equipped with metering equipment that can measure the flow of electricity in both directions at the same rate. (1) For eligible customers whose electric service has |
| not been declared competitive pursuant to Section 16-113 of this Act as of July 1, 2011 and whose electric delivery service is provided and measured on a kilowatt-hour basis and electric supply service is not provided based on hourly pricing, this shall typically be accomplished through use of a single, bi-directional meter. If the eligible customer's existing electric revenue meter does not meet this requirement, the electricity provider shall arrange for the local electric utility or a meter service provider to install and maintain a new revenue meter at the electricity provider's expense, which may be the smart meter described by subsection (b) of Section 16-108.5 of this Act.
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(2) For eligible customers whose electric service has
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| not been declared competitive pursuant to Section 16-113 of this Act as of July 1, 2011 and whose electric delivery service is provided and measured on a kilowatt demand basis and electric supply service is not provided based on hourly pricing, this shall typically be accomplished through use of a dual channel meter capable of measuring the flow of electricity both into and out of the customer's facility at the same rate and ratio. If such customer's existing electric revenue meter does not meet this requirement, then the electricity provider shall arrange for the local electric utility or a meter service provider to install and maintain a new revenue meter at the electricity provider's expense, which may be the smart meter described by subsection (b) of Section 16-108.5 of this Act.
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(3) For all other eligible customers, until such time
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| as the local electric utility installs a smart meter, as described by subsection (b) of Section 16-108.5 of this Act, the electricity provider may arrange for the local electric utility or a meter service provider to install and maintain metering equipment capable of measuring the flow of electricity both into and out of the customer's facility at the same rate and ratio, typically through the use of a dual channel meter. If the eligible customer's existing electric revenue meter does not meet this requirement, then the costs of installing such equipment shall be paid for by the customer.
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(d) An electricity provider shall
measure and charge or credit for the net
electricity supplied to eligible customers or provided by eligible customers whose electric service has not been declared competitive pursuant to Section 16-113 of this Act as of July 1, 2011 and whose electric delivery service is provided and measured on a kilowatt-hour basis and electric supply service is not provided based on hourly pricing in
the following manner:
(1) If the amount of electricity used by the customer
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| during the billing period exceeds the amount of electricity produced by the customer, the electricity provider shall charge the customer for the net electricity supplied to and used by the customer as provided in subsection (e-5) of this Section.
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(2) If the amount of electricity produced by a
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| customer during the billing period exceeds the amount of electricity used by the customer during that billing period, the electricity provider supplying that customer shall apply a 1:1 kilowatt-hour credit to a subsequent bill for service to the customer for the net electricity supplied to the electricity provider. The electricity provider shall continue to carry over any excess kilowatt-hour credits earned and apply those credits to subsequent billing periods to offset any customer-generator consumption in those billing periods until all credits are used or until the end of the annualized period.
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(3) At the end of the year or annualized over the
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| period that service is supplied by means of net metering, or in the event that the retail customer terminates service with the electricity provider prior to the end of the year or the annualized period, any remaining credits in the customer's account shall expire.
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(d-5) An electricity provider shall measure and charge or credit for the net electricity
supplied to eligible customers or provided by eligible customers whose electric service has not
been declared competitive pursuant to Section 16-113 of this Act as of July 1, 2011 and whose electric delivery
service is provided and measured on a kilowatt-hour basis and electric supply service is provided
based on hourly pricing or time-of-use rates in the following manner:
(1) If the amount of electricity used by the customer
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| during any hourly period or time-of-use period exceeds the amount of electricity produced by the customer, the electricity provider shall charge the customer for the net electricity supplied to and used by the customer according to the terms of the contract or tariff to which the same customer would be assigned to or be eligible for if the customer was not a net metering customer.
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(2) If the amount of electricity produced by a
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| customer during any hourly period or time-of-use period exceeds the amount of electricity used by the customer during that hourly period or time-of-use period, the energy provider shall apply a credit for the net kilowatt-hours produced in such period. The credit shall consist of an energy credit and a delivery service credit. The energy credit shall be valued at the same price per kilowatt-hour as the electric service provider would charge for kilowatt-hour energy sales during that same hourly period or time-of-use period. The delivery credit shall be equal to the net kilowatt-hours produced in such hourly period or time-of-use period times a credit that reflects all kilowatt-hour based charges in the customer's electric service rate, excluding energy charges.
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(e) An electricity provider shall measure and charge or credit for the net electricity supplied to eligible customers whose electric service has not been declared competitive pursuant to Section 16-113 of this Act as of July 1, 2011 and whose electric delivery service is provided and measured on a kilowatt demand basis and electric supply service is not provided based on hourly pricing in the following manner:
(1) If the amount of electricity used by the customer
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| during the billing period exceeds the amount of electricity produced by the customer, then the electricity provider shall charge the customer for the net electricity supplied to and used by the customer as provided in subsection (e-5) of this Section. The customer shall remain responsible for all taxes, fees, and utility delivery charges that would otherwise be applicable to the net amount of electricity used by the customer.
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(2) If the amount of electricity produced by a
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| customer during the billing period exceeds the amount of electricity used by the customer during that billing period, then the electricity provider supplying that customer shall apply a 1:1 kilowatt-hour credit that reflects the kilowatt-hour based charges in the customer's electric service rate to a subsequent bill for service to the customer for the net electricity supplied to the electricity provider. The electricity provider shall continue to carry over any excess kilowatt-hour credits earned and apply those credits to subsequent billing periods to offset any customer-generator consumption in those billing periods until all credits are used or until the end of the annualized period.
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(3) At the end of the year or annualized over the
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| period that service is supplied by means of net metering, or in the event that the retail customer terminates service with the electricity provider prior to the end of the year or the annualized period, any remaining credits in the customer's account shall expire.
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(e-5) An electricity provider shall provide electric service to eligible customers who utilize net metering at non-discriminatory rates that are identical, with respect to rate structure, retail rate components, and any monthly charges, to the rates that the customer would be charged if not a net metering customer. An electricity provider shall not charge net metering customers any fee or charge or require additional equipment, insurance, or any other requirements not specifically authorized by interconnection standards authorized by the Commission, unless the fee, charge, or other requirement would apply to other similarly situated customers who are not net metering customers. The customer will remain responsible for all taxes, fees, and utility delivery charges that would otherwise be applicable to the net amount of electricity used by the customer. Subsections (c) through (e) of this Section shall not be construed to prevent an arms-length agreement between an electricity provider and an eligible customer that sets forth different prices, terms, and conditions for the provision of net metering service, including, but not limited to, the provision of the appropriate metering equipment for non-residential customers.
(f) Notwithstanding the requirements of subsections (c) through (e-5) of this Section, an electricity provider must require dual-channel metering for customers operating eligible renewable electrical generating facilities to whom the provisions of neither subsection (d), (d-5), nor (e) of this Section apply. In such cases, electricity charges and credits shall be determined as follows:
(1) The electricity provider shall assess and the
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| customer remains responsible for all taxes, fees, and utility delivery charges that would otherwise be applicable to the gross amount of kilowatt-hours supplied to the eligible customer by the electricity provider.
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(2) Each month that service is supplied by means of
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| dual-channel metering, the electricity provider shall compensate the eligible customer for any excess kilowatt-hour credits at the electricity provider's avoided cost of electricity supply over the monthly period or as otherwise specified by the terms of a power-purchase agreement negotiated between the customer and electricity provider.
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(3) For all eligible net metering customers taking
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| service from an electricity provider under contracts or tariffs employing hourly or time-of-use rates, any monthly consumption of electricity shall be calculated according to the terms of the contract or tariff to which the same customer would be assigned to or be eligible for if the customer was not a net metering customer. When those same customer-generators are net generators during any discrete hourly or time-of-use period, the net kilowatt-hours produced shall be valued at the same price per kilowatt-hour as the electric service provider would charge for retail kilowatt-hour sales during that same time-of-use period.
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(g) For purposes of federal and State laws providing renewable energy credits or greenhouse gas credits, the eligible customer shall be treated as owning and having title to the renewable energy attributes, renewable energy credits, and greenhouse gas emission credits related to any electricity produced by the qualified generating unit. The electricity provider may not condition participation in a net metering program on the signing over of a customer's renewable energy credits; provided, however, this subsection (g) shall not be construed to prevent an arms-length agreement between an electricity provider and an eligible customer that sets forth the ownership or title of the credits.
(h) Within 120 days after the effective date of this
amendatory Act of the 95th General Assembly, the Commission shall establish standards for net metering and, if the Commission has not already acted on its own initiative, standards for the interconnection of eligible renewable generating equipment to the utility system. The interconnection standards shall address any procedural barriers, delays, and administrative costs associated with the interconnection of customer-generation while ensuring the safety and reliability of the units and the electric utility system. The Commission shall consider the Institute of Electrical and Electronics Engineers (IEEE) Standard 1547 and the issues of (i) reasonable and fair fees and costs, (ii) clear timelines for major milestones in the interconnection process, (iii) nondiscriminatory terms of agreement, and (iv) any best practices for interconnection of distributed generation.
(h-5) Within 90 days after the effective date of this
amendatory Act of the 102nd General Assembly, the Commission
shall:
(1) establish an Interconnection Working Group. The
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| working group shall include representatives from electric utilities, developers of renewable electric generating facilities, other industries that regularly apply for interconnection with the electric utilities, representatives of distributed generation customers, the Commission Staff, and such other stakeholders with a substantial interest in the topics addressed by the Interconnection Working Group. The Interconnection Working Group shall address at least the following issues:
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(A) cost and best available technology for
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| interconnection and metering, including the standardization and publication of standard costs;
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(B) transparency, accuracy and use of the
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| distribution interconnection queue and hosting capacity maps;
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(C) distribution system upgrade cost avoidance
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| through use of advanced inverter functions;
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(D) predictability of the queue management
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| process and enforcement of timelines;
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(E) benefits and challenges associated with group
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| studies and cost sharing;
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(F) minimum requirements for application to the
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| interconnection process and throughout the interconnection process to avoid queue clogging behavior;
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(G) process and customer service for
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| interconnecting customers adopting distributed energy resources, including energy storage;
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(H) options for metering distributed energy
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| resources, including energy storage;
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(I) interconnection of new technologies,
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| including smart inverters and energy storage;
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(J) collect, share, and examine data on Level 1
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| interconnection costs, including cost and type of upgrades required for interconnection, and use this data to inform the final standardized cost of Level 1 interconnection; and
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(K) such other technical, policy, and tariff
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| issues related to and affecting interconnection performance and customer service as determined by the Interconnection Working Group.
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The Commission may create subcommittees of the
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| Interconnection Working Group to focus on specific issues of importance, as appropriate. The Interconnection Working Group shall report to the Commission on recommended improvements to interconnection rules and tariffs and policies as determined by the Interconnection Working Group at least every 6 months. Such reports shall include consensus recommendations of the Interconnection Working Group and, if applicable, additional recommendations for which consensus was not reached. The Commission shall use the report from the Interconnection Working Group to determine whether processes should be commenced to formally codify or implement the recommendations;
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(2) create or contract for an Ombudsman to resolve
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| interconnection disputes through non-binding arbitration. The Ombudsman may be paid in full or in part through fees levied on the initiators of the dispute; and
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(3) determine a single standardized cost for Level 1
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| interconnections, which shall not exceed $200.
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(i) All electricity providers shall begin to offer net metering
no later than April 1,
2008.
(j) An electricity provider shall provide net metering to eligible
customers according to subsections (d), (d-5), and
(e). Eligible renewable electrical generating facilities for which eligible customers registered for net metering before January 1, 2025 shall continue to receive net metering services according to subsections (d), (d-5), and (e) of this Section for the lifetime of the system, regardless of whether those retail customers change electricity providers or whether the retail customer benefiting from the system changes. On and after January 1, 2025, any eligible customer that applies for net metering and previously would have qualified under subsections (d), (d-5), or (e) shall only be eligible for net metering as described in subsection (n).
(k) Each electricity provider shall maintain records and report annually to the Commission the total number of net metering customers served by the provider, as well as the type, capacity, and energy sources of the generating systems used by the net metering customers. Nothing in this Section shall limit the ability of an electricity provider to request the redaction of information deemed by the Commission to be confidential business information.
(l)(1) Notwithstanding the definition of "eligible customer" in item (ii) of subsection (b) of this Section, each electricity provider shall allow net metering as set forth in this subsection (l) and for the following projects, provided that only electric utilities serving more than 200,000 customers as of January 1, 2021 shall provide net metering for projects that are eligible for subparagraph (C) of this paragraph (1) and have energized after the effective date of this amendatory Act of the 102nd General Assembly:
(A) properties owned or leased by multiple customers
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| that contribute to the operation of an eligible renewable electrical generating facility through an ownership or leasehold interest of at least 200 watts in such facility, such as a community-owned wind project, a community-owned biomass project, a community-owned solar project, or a community methane digester processing livestock waste from multiple sources, provided that the facility is also located within the utility's service territory;
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(B) individual units, apartments, or properties
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| located in a single building that are owned or leased by multiple customers and collectively served by a common eligible renewable electrical generating facility, such as an office or apartment building, a shopping center or strip mall served by photovoltaic panels on the roof; and
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(C) subscriptions to community renewable
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| generation projects, including community renewable generation projects on the customer's side of the billing meter of a host facility and partially used for the customer's own load.
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In addition, the nameplate capacity of the eligible renewable electric generating facility that serves the demand of the properties, units, or apartments identified in paragraphs (1) and (2) of this subsection (l) shall not exceed 5,000 kilowatts in nameplate capacity in total.
Any eligible renewable electrical generating facility or community renewable generation project that is powered by photovoltaic electric energy and installed after the effective date of this amendatory Act of the 99th General Assembly must be installed by a qualified person in compliance with the requirements of Section 16-128A of the Public Utilities Act and any rules or regulations adopted thereunder.
(2) Notwithstanding anything to the contrary, an electricity provider shall provide credits for the electricity produced by the projects described in paragraph (1) of this subsection (l). The electricity provider shall provide credits that include at least energy supply, capacity, transmission, and, if applicable, the purchased energy adjustment on the subscriber's monthly bill equal to the subscriber's share of the production of electricity from the project, as determined by paragraph (3) of this subsection (l). For customers with transmission or capacity charges not charged on a kilowatt-hour basis, the electricity provider shall prepare a reasonable approximation of the kilowatt-hour equivalent value and provide that value as a monetary credit. The electricity provider shall submit these approximation methodologies to the Commission for review, modification, and approval. Notwithstanding anything to the contrary, customers on payment plans or participating in budget billing programs shall have credits applied on a monthly basis.
(3) Notwithstanding anything to the contrary and regardless of whether a subscriber to an eligible community renewable generation project receives power and energy service from the electric utility or an alternative retail electric supplier, for projects eligible under paragraph (C) of subparagraph (1) of this subsection (l), electric utilities serving more than 200,000 customers as of January 1, 2021 shall provide the monetary credits to a subscriber's subsequent bill for the electricity produced by community renewable generation projects. The electric utility shall provide monetary credits to a subscriber's subsequent bill at the utility's total price to compare equal to the subscriber's share of the production of electricity from the project, as determined by paragraph (5) of this subsection (l). For the purposes of this subsection, "total price to compare" means the rate or rates published by the Illinois Commerce Commission for energy supply for eligible customers receiving supply service from the electric utility, and shall include energy, capacity, transmission, and the purchased energy adjustment. Notwithstanding anything to the contrary, customers on payment plans or participating in budget billing programs shall have credits applied on a monthly basis. Any applicable credit or reduction in load obligation from the production of the community renewable generating projects receiving a credit under this subsection shall be credited to the electric utility to offset the cost of providing the credit. To the extent that the credit or load obligation reduction does not completely offset the cost of providing the credit to subscribers of community renewable generation projects as described in this subsection, the electric utility may recover the remaining costs through its Multi-Year Rate Plan. All electric utilities serving 200,000 or fewer customers as of January 1, 2021 shall only provide the monetary credits to a subscriber's subsequent bill for the electricity produced by community renewable generation projects if the subscriber receives power and energy service from the electric utility. Alternative retail electric suppliers providing power and energy service to a subscriber located within the service territory of an electric utility not subject to Sections 16-108.18 and 16-118 shall provide the monetary credits to the subscriber's subsequent bill for the electricity produced by community renewable generation projects.
(4) If requested by the owner or operator of a community renewable generating project, an electric utility serving more than 200,000 customers as of January 1, 2021 shall enter into a net crediting agreement with the owner or operator to include a subscriber's subscription fee on the subscriber's monthly electric bill and provide the subscriber with a net credit equivalent to the total bill credit value for that generation period minus the subscription fee, provided the subscription fee is structured as a fixed percentage of bill credit value. The net crediting agreement shall set forth payment terms from the electric utility to the owner or operator of the community renewable generating project, and the electric utility may charge a net crediting fee to the owner or operator of a community renewable generating project that may not exceed 2% of the bill credit value. Notwithstanding anything to the contrary, an electric utility serving 200,000 customers or fewer as of January 1, 2021 shall not be obligated to enter into a net crediting agreement with the owner or operator of a community renewable generating project.
(5) For the purposes of facilitating net metering, the owner or operator of the eligible renewable electrical generating facility or community renewable generation project shall be responsible for determining the amount of the credit that each customer or subscriber participating in a project under this subsection (l) is to receive in the following manner:
(A) The owner or operator shall, on a monthly
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| basis, provide to the electric utility the kilowatthours of generation attributable to each of the utility's retail customers and subscribers participating in projects under this subsection (l) in accordance with the customer's or subscriber's share of the eligible renewable electric generating facility's or community renewable generation project's output of power and energy for such month. The owner or operator shall electronically transmit such calculations and associated documentation to the electric utility, in a format or method set forth in the applicable tariff, on a monthly basis so that the electric utility can reflect the monetary credits on customers' and subscribers' electric utility bills. The electric utility shall be permitted to revise its tariffs to implement the provisions of this amendatory Act of the 102nd General Assembly. The owner or operator shall separately provide the electric utility with the documentation detailing the calculations supporting the credit in the manner set forth in the applicable tariff.
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(B) For those participating customers and
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| subscribers who receive their energy supply from an alternative retail electric supplier, the electric utility shall remit to the applicable alternative retail electric supplier the information provided under subparagraph (A) of this paragraph (3) for such customers and subscribers in a manner set forth in such alternative retail electric supplier's net metering program, or as otherwise agreed between the utility and the alternative retail electric supplier. The alternative retail electric supplier shall then submit to the utility the amount of the charges for power and energy to be applied to such customers and subscribers, including the amount of the credit associated with net metering.
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(C) A participating customer or subscriber may
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| provide authorization as required by applicable law that directs the electric utility to submit information to the owner or operator of the eligible renewable electrical generating facility or community renewable generation project to which the customer or subscriber has an ownership or leasehold interest or a subscription. Such information shall be limited to the components of the net metering credit calculated under this subsection (l), including the bill credit rate, total kilowatthours, and total monetary credit value applied to the customer's or subscriber's bill for the monthly billing period.
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(l-5) Within 90 days after the effective date of this amendatory Act of the 102nd General Assembly, each electric utility subject to this Section shall file a tariff or tariffs to implement the provisions of subsection (l) of this Section, which shall, consistent with the provisions of subsection (l), describe the terms and conditions under which owners or operators of qualifying properties, units, or apartments may participate in net metering. The Commission shall approve, or approve with modification, the tariff within 120 days after the effective date of this amendatory Act of the 102nd General Assembly.
(m) Nothing in this Section shall affect the right of an electricity provider to continue to provide, or the right of a retail customer to continue to receive service pursuant to a contract for electric service between the electricity provider and the retail customer in accordance with the prices, terms, and conditions provided for in that contract. Either the electricity provider or the customer may require compliance with the prices, terms, and conditions of the contract.
(n) On and after January 1, 2025, the net metering services described in subsections (d), (d-5), and (e) of this Section shall no longer be offered, except as to those eligible renewable electrical generating facilities for which retail customers are receiving net metering service under these subsections at the time the net metering services under those subsections are no longer offered; those systems shall continue to receive net metering services described in subsections (d), (d-5), and (e) of this Section for the lifetime of the system, regardless of if those retail customers change electricity providers or whether the retail customer benefiting from the system changes. The electric utility serving more than 200,000 customers as of January 1, 2021 is responsible for ensuring the billing credits continue without lapse for the lifetime of systems, as required in subsection (o). Those retail customers that begin taking net metering service after the date that net metering services are no longer offered under such subsections shall be subject to the provisions set forth in the following paragraphs (1) through (3) of this subsection (n):
(1) An electricity provider shall charge or credit
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| for the net electricity supplied to eligible customers or provided by eligible customers whose electric supply service is not provided based on hourly pricing in the following manner:
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(A) If the amount of electricity used by the
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| customer during the monthly billing period exceeds the amount of electricity produced by the customer, then the electricity provider shall charge the customer for the net kilowatt-hour based electricity charges reflected in the customer's electric service rate supplied to and used by the customer as provided in paragraph (3) of this subsection (n).
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(B) If the amount of electricity produced by a
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| customer during the monthly billing period exceeds the amount of electricity used by the customer during that billing period, then the electricity provider supplying that customer shall apply a 1:1 kilowatt-hour energy or monetary credit kilowatt-hour supply charges to the customer's subsequent bill. The customer shall choose between 1:1 kilowatt-hour or monetary credit at the time of application. For the purposes of this subsection, "kilowatt-hour supply charges" means the kilowatt-hour equivalent values for energy, capacity, transmission, and the purchased energy adjustment, if applicable. Notwithstanding anything to the contrary, customers on payment plans or participating in budget billing programs shall have credits applied on a monthly basis. The electricity provider shall continue to carry over any excess kilowatt-hour or monetary energy credits earned and apply those credits to subsequent billing periods. For customers with transmission or capacity charges not charged on a kilowatt-hour basis, the electricity provider shall prepare a reasonable approximation of the kilowatt-hour equivalent value and provide that value as a monetary credit. The electricity provider shall submit these approximation methodologies to the Commission for review, modification, and approval.
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(C) (Blank).
(2) An electricity provider shall charge or credit
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| for the net electricity supplied to eligible customers or provided by eligible customers whose electric supply service is provided based on hourly pricing in the following manner:
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(A) If the amount of electricity used by the
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| customer during any hourly period exceeds the amount of electricity produced by the customer, then the electricity provider shall charge the customer for the net electricity supplied to and used by the customer as provided in paragraph (3) of this subsection (n).
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(B) If the amount of electricity produced by a
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| customer during any hourly period exceeds the amount of electricity used by the customer during that hourly period, the energy provider shall calculate an energy credit for the net kilowatt-hours produced in such period, and shall apply that credit as a monetary credit to the customer's subsequent bill. The value of the energy credit shall be calculated using the same price per kilowatt-hour as the electric service provider would charge for kilowatt-hour energy sales during that same hourly period and shall also include values for capacity and transmission. For customers with transmission or capacity charges not charged on a kilowatt-hour basis, the electricity provider shall prepare a reasonable approximation of the kilowatt-hour equivalent value and provide that value as a monetary credit. The electricity provider shall submit these approximation methodologies to the Commission for review, modification, and approval. Notwithstanding anything to the contrary, customers on payment plans or participating in budget billing programs shall have credits applied on a monthly basis.
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(3) An electricity provider shall provide electric
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| service to eligible customers who utilize net metering at non-discriminatory rates that are identical, with respect to rate structure, retail rate components, and any monthly charges, to the rates that the customer would be charged if not a net metering customer. An electricity provider shall charge the customer for the net electricity supplied to and used by the customer according to the terms of the contract or tariff to which the same customer would be assigned or be eligible for if the customer was not a net metering customer. An electricity provider shall not charge net metering customers any fee or charge or require additional equipment, insurance, or any other requirements not specifically authorized by interconnection standards authorized by the Commission, unless the fee, charge, or other requirement would apply to other similarly situated customers who are not net metering customers. The customer remains responsible for the gross amount of delivery services charges, supply-related charges that are kilowatt based, and all taxes and fees related to such charges. The customer also remains responsible for all taxes and fees that would otherwise be applicable to the net amount of electricity used by the customer. Paragraphs (1) and (2) of this subsection (n) shall not be construed to prevent an arms-length agreement between an electricity provider and an eligible customer that sets forth different prices, terms, and conditions for the provision of net metering service, including, but not limited to, the provision of the appropriate metering equipment for non-residential customers. Nothing in this paragraph (3) shall be interpreted to mandate that a utility that is only required to provide delivery services to a given customer must also sell electricity to such customer.
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(o) Within 90 days after the effective date of this amendatory Act of the 102nd General Assembly, each electric utility subject to this Section shall file a tariff, which shall, consistent with the provisions of this Section, propose the terms and conditions under which a customer may participate in net metering. The tariff for electric utilities serving more than 200,000 customers as of January 1, 2021 shall also provide a streamlined and transparent bill crediting system for net metering to be managed by the electric utilities. The terms and conditions shall include, but are not limited to, that an electric utility shall manage and maintain billing of net metering credits and charges regardless of if the eligible customer takes net metering under an electric utility or alternative retail electric supplier. The electric utility serving more than 200,000 customers as of January 1, 2021 shall process and approve all net metering applications, even if an eligible customer is served by an alternative retail electric supplier; and the utility shall forward application approval to the appropriate alternative retail electric supplier. Eligibility for net metering shall remain with the owner of the utility billing address such that, if an eligible renewable electrical generating facility changes ownership, the net metering eligibility transfers to the new owner. The electric utility serving more than 200,000 customers as of January 1, 2021 shall manage net metering billing for eligible customers to ensure full crediting occurs on electricity bills, including, but not limited to, ensuring net metering crediting begins upon commercial operation date, net metering billing transfers immediately if an eligible customer switches from an electric utility to alternative retail electric supplier or vice versa, and net metering billing transfers between ownership of a valid billing address. All transfers referenced in the preceding sentence shall include transfer of all banked credits. All electric utilities serving 200,000 or fewer customers as of January 1, 2021 shall manage net metering billing for eligible customers receiving power and energy service from the electric utility to ensure full crediting occurs on electricity bills, ensuring net metering crediting begins upon commercial operation date, net metering billing transfers immediately if an eligible customer switches from an electric utility to alternative retail electric supplier or vice versa, and net metering billing transfers between ownership of a valid billing address. Alternative retail electric suppliers providing power and energy service to eligible customers located within the service territory of an electric utility serving 200,000 or fewer customers as of January 1, 2021 shall manage net metering billing for eligible customers to ensure full crediting occurs on electricity bills, including, but not limited to, ensuring net metering crediting begins upon commercial operation date, net metering billing transfers immediately if an eligible customer switches from an electric utility to alternative retail electric supplier or vice versa, and net metering billing transfers between ownership of a valid billing address.
(Source: P.A. 102-662, eff. 9-15-21.)
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(220 ILCS 5/16-107.6) Sec. 16-107.6. Distributed generation rebate. (a) In this Section: "Additive services" means the services that distributed energy resources provide to the energy system and society that are not (1) already included in the base rebates for system-wide grid services; or (2) otherwise already compensated. Additive services may reflect, but shall not be limited to, any geographic, time-based, performance-based, and other benefits of distributed energy resources, as well as the present and future technological capabilities of distributed energy resources and present and future grid needs. "Distributed energy resource" means a wide range of technologies that are located on the customer side of the customer's electric meter, including, but not limited to, distributed generation, energy storage, electric vehicles, and demand response technologies. "Energy storage system" means commercially available technology that is capable of absorbing energy and storing it for a period of time for use at a later time, including, but not limited to, electrochemical, thermal, and electromechanical technologies, and may be interconnected behind the customer's meter or interconnected behind its own meter. "Smart inverter" means a device that converts direct current
into alternating current and meets the IEEE 1547-2018 equipment standards. Until devices that meet the IEEE 1547-2018 standard are available, devices that meet the UL 1741 SA standard are acceptable. "Subscriber" has the meaning set forth in Section 1-10 of the Illinois Power Agency Act. "Subscription" has the meaning set forth in Section 1-10 of the Illinois Power Agency Act. "System-wide grid services" means the benefits that a distributed energy resource provides to the distribution grid for a period of no less than 25 years. System-wide grid services do not vary by location, time, or the performance characteristics of the distributed energy resource. System-wide grid services include, but are not limited to, avoided or deferred distribution capacity costs, resilience and reliability benefits, avoided or deferred distribution operation and maintenance costs, distribution voltage and power quality benefits, and line loss reductions. "Threshold date" means December 31, 2024 or the date on which the utility's tariff or tariffs setting the new compensation values established under subsection (e) take effect, whichever is later. (b) An electric utility that serves more than 200,000 customers in the State shall file a petition with the Commission requesting approval of the utility's tariff to provide a rebate to the owner or operator of distributed generation, including third-party owned systems, that meets the following criteria: (1) has a nameplate generating capacity no greater |
| than 5,000 kilowatts and is primarily used to offset a customer's electricity load;
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(2) is located on the customer's side of the billing
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| meter and for the customer's own use;
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(3) is interconnected to electric distribution
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| facilities owned by the electric utility under rules adopted by the Commission by means of the inverter or smart inverter required by this Section, as applicable.
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For purposes of this Section, "distributed generation" shall satisfy the definition of distributed renewable energy generation device set forth in Section 1-10 of the Illinois Power Agency Act to the extent such definition is consistent with the requirements of this Section.
In addition, any new photovoltaic distributed generation that is installed after June 1, 2017 (the effective date of Public Act 99-906) must be installed by a qualified person, as defined by subsection (i) of Section 1-56 of the Illinois Power Agency Act.
The tariff shall include a base rebate that compensates distributed generation for the system-wide grid services associated with distributed generation and, after the proceeding described in subsection (e) of this Section, an additional payment or payments for the additive services. The tariff shall provide that the smart inverter associated with the distributed generation shall provide autonomous response to grid conditions through its default settings as approved by the Commission. Default settings may not be changed after the execution of the interconnection agreement except by mutual agreement between the utility and the owner or operator of the distributed generation. Nothing in this Section shall negate or supersede Institute of Electrical and Electronics Engineers equipment standards or other similar standards or requirements. The tariff shall not limit the ability of the smart inverter or other distributed energy resource to provide wholesale market products such as regulation, demand response, or other services, or limit the ability of the owner of the smart inverter or the other distributed energy resource to receive compensation for providing those wholesale market products or services.
(b-5) Within 30 days after the effective date of this amendatory Act of the 102nd General Assembly, each electric public utility with 3,000,000 or more retail customers shall file a tariff with the Commission that further compensates any retail customer that installs or has installed photovoltaic facilities paired with energy storage facilities on or adjacent to its premises for the benefits the facilities provide to the distribution grid. The tariff shall provide that, in addition to the other rebates identified in this Section, the electric utility shall rebate to such retail customer (i) the previously incurred and future costs of installing interconnection facilities and related infrastructure to enable full participation in the PJM Interconnection, LLC or its successor organization frequency regulation market; and (ii) all wholesale demand charges incurred after the effective date of this amendatory Act of the 102nd General Assembly. The Commission shall approve, or approve with modification, the tariff within 120 days after the utility's filing.
(c) The proposed tariff authorized by subsection (b) of this Section shall include the following participation terms for rebates to be applied under this Section for distributed generation that satisfies the criteria set forth in subsection (b) of this Section:
(1) The owner or operator of distributed generation
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| that services customers not eligible for net metering under subsection (d), (d-5), or (e) of Section 16-107.5 of this Act may apply for a rebate as provided for in this Section. Until the threshold date, the value of the rebate shall be $250 per kilowatt of nameplate generating capacity, measured as nominal DC power output, of that customer's distributed generation. To the extent the distributed generation also has an associated energy storage, then the energy storage system shall be separately compensated with a base rebate of $250 per kilowatt-hour of nameplate capacity. Any distributed generation device that is compensated for storage in this subsection (1) before the threshold date shall participate in one or more programs determined through the Multi-Year Integrated Grid Planning process that are designed to meet peak reduction and flexibility. After the threshold date, the value of the base rebate and additional compensation for any additive services shall be as determined by the Commission in the proceeding described in subsection (e) of this Section, provided that the value of the base rebate for system-wide grid services shall not be lower than $250 per kilowatt of nameplate generating capacity of distributed generation or community renewable generation project.
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(2) The owner or operator of distributed generation
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| that, before the threshold date, would have been eligible for net metering under subsection (d), (d-5), or (e) of Section 16-107.5 of this Act and that has not previously received a distributed generation rebate, may apply for a rebate as provided for in this Section. Until the threshold date, the value of the base rebate shall be $300 per kilowatt of nameplate generating capacity, measured as nominal DC power output, of the distributed generation. The owner or operator of distributed generation that, before the threshold date, is eligible for net metering under subsection (d), (d-5), or (e) of Section 16-107.5 of this Act may apply for a base rebate for an energy storage device that uses the same smart inverter as the distributed generation, regardless of whether the distributed generation applies for a rebate for the distributed generation device. The energy storage system shall be separately compensated at a base payment of $300 per kilowatt-hour of nameplate capacity. Any distributed generation device that is compensated for storage in this subsection (2) before the threshold date shall participate in a peak time rebate program, hourly pricing program, or time-of-use rate program offered by the applicable electric utility. After the threshold date, the value of the base rebate and additional compensation for any additive services shall be as determined by the Commission in the proceeding described in subsection (e) of this Section, provided that, prior to December 31, 2029, the value of the base rebate for system-wide services shall not be lower than $300 per kilowatt of nameplate generating capacity of distributed generation, after which it shall not be lower than $250 per kilowatt of nameplate capacity.
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(3) Upon approval of a rebate application submitted
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| under this subsection (c), the retail customer shall no longer be entitled to receive any delivery service credits for the excess electricity generated by its facility and shall be subject to the provisions of subsection (n) of Section 16-107.5 of this Act unless the owner or operator receives a rebate only for an energy storage device and not for the distributed generation device.
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(4) To be eligible for a rebate described in this
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| subsection (c), the owner or operator of the distributed generation must have a smart inverter installed and in operation on the distributed generation.
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(d) The Commission shall review the proposed tariff authorized by subsection (b) of this Section and may make changes to the tariff that are consistent with this Section and with the Commission's authority under Article IX of this Act, subject to notice and hearing. Following notice and hearing, the Commission shall issue an order approving, or approving with modification, such tariff no later than 240 days after the utility files its tariff. Upon the effective date of this amendatory Act of the 102nd General Assembly, an electric utility shall file a petition with the Commission to amend and update any existing tariffs to comply with subsections (b) and (c).
(e) By no later than June 30, 2023, the Commission shall open an independent, statewide investigation into the value of, and compensation for, distributed energy resources. The Commission shall conduct the investigation, but may arrange for experts or consultants independent of the utilities and selected by the Commission to assist with the investigation. The cost of the investigation shall be shared by the utilities filing tariffs under subsection (b) of this Section but may be recovered as an expense through normal ratemaking procedures.
(1) The Commission shall ensure that the
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| investigation includes, at minimum, diverse sets of stakeholders; a review of best practices in calculating the value of distributed energy resource benefits; a review of the full value of the distributed energy resources and the manner in which each component of that value is or is not otherwise compensated; and assessments of how the value of distributed energy resources may evolve based on the present and future technological capabilities of distributed energy resources and based on present and future grid needs.
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(2) The Commission's final order concluding this
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| investigation shall establish an annual process and formula for the compensation of distributed generation and energy storage systems, and an initial set of inputs for that formula. The Commission's final order concluding this investigation shall establish base rebates that compensate distributed generation, community renewable generation projects and energy storage systems for the system-wide grid services that they provide. Those base rebate values shall be consistent across the state, and shall not vary by customer, customer class, customer location, or any other variable. With respect to rebates for distributed generation or community renewable generation projects, that rebate shall not be lower than $250 per kilowatt of nameplate generating capacity of the distributed generation or community renewable generation project. The Commission's final order concluding this proceeding shall also direct the utilities to update the formula, on an annual basis, with inputs derived from their integrated grid plans developed pursuant to Section 16-105.17. The base rebate shall be updated annually based on the annual updates to the formula inputs, but, with respect to rebates for distributed generation or community renewable generation projects, shall be no lower than $250 per kilowatt of nameplate generating capacity of the distributed generation or community renewable generation project.
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(3) The Commission shall also determine, as a part of
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| its investigation under this subsection, whether distributed energy resources can provide any additive services. Those additive services may include services that are provided through utility-controlled responses to grid conditions. If the Commission determines that distributed energy resources can provide additive grid services, the Commission shall determine the terms and conditions for the operation and compensation of those services. That compensation shall be above and beyond the base rebate that the distributed energy generation, community renewable generation project and energy storage system receives. Compensation for additive services may vary by location, time, performance characteristics, technology types, or other variables.
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(4) The Commission shall ensure that compensation for
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| distributed energy resources, including base rebates and any payments for additive services, shall reflect all reasonably known and measurable values of the distributed generation over its full expected useful life. Compensation for additive services shall reflect, but shall not be limited to, any geographic, time-based, performance-based, and other benefits of distributed generation, as well as the present and future technological capabilities of distributed energy resources and present and future grid needs.
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(5) The Commission shall consider the electric
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| utility's integrated grid plan developed pursuant to Section 16-105.17 of this Act to help identify the value of distributed energy resources for the purpose of calculating the compensation described in this subsection.
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(6) The Commission shall determine additional
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| compensation for distributed energy resources that creates savings and value on the distribution system by being co-located or in close proximity to electric vehicle charging infrastructure in use by medium-duty and heavy-duty vehicles, primarily serving environmental justice communities, as outlined in the utility integrated grid planning process under Section 16-105.17 of this Act.
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No later than 60 days after the Commission enters its final order under this subsection (e), each utility shall file its updated tariff or tariffs in compliance with the order, including new tariffs for the recovery of costs incurred under this subsection (e) that shall provide for volumetric-based cost recovery, and the Commission shall approve, or approve with modification, the tariff or tariffs within 240 days after the utility's filing.
(f) Notwithstanding any provision of this Act to the contrary, the owner or operator of a community renewable generation project as defined in Section 1-10 of the Illinois Power Agency Act shall also be eligible to apply for the rebate described in this Section. The owner or operator of the community renewable generation project may apply for a rebate only if the owner or operator, or previous owner or operator, of the community renewable generation project has not already submitted an application, and, regardless of whether the subscriber is a residential or non-residential customer, may be allowed the amount identified in paragraph (1) of subsection (c) applicable on the date that the application is submitted.
(g) The owner of the distributed generation or community renewable generation project may apply for the rebate or rebates approved under this Section at the time of execution of an interconnection agreement with the distribution utility and shall receive the value available at that time of execution of the interconnection agreement, provided the project reaches mechanical completion within 24 months after execution of the interconnection agreement. If the project has not reached mechanical completion within 24 months after execution, the owner may reapply for the rebate or rebates approved under this Section available at the time of application and shall receive the value available at the time of application. The utility shall issue the rebate no later than 60 days after the project is energized. In the event the application is incomplete or the utility is otherwise unable to calculate the payment based on the information provided by the owner, the utility shall issue the payment no later than 60 days after the application is complete or all requested information is received.
(h) An electric utility shall recover from its retail customers all of the costs of the rebates made under a tariff or tariffs approved under subsection (d) of this Section, including, but not limited to, the value of the rebates and all costs incurred by the utility to comply with and implement subsections (b) and (c) of this Section, but not including costs incurred by the utility to comply with and implement subsection (e) of this Section, consistent with the following provisions:
(1) The utility shall defer the full amount of its
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| costs as a regulatory asset. The total costs deferred as a regulatory asset shall be amortized over a 15-year period. The unamortized balance shall be recognized as of December 31 for a given year. The utility shall also earn a return on the total of the unamortized balance of the regulatory assets, less any deferred taxes related to the unamortized balance, at an annual rate equal to the utility's weighted average cost of capital that includes, based on a year-end capital structure, the utility's actual cost of debt for the applicable calendar year and a cost of equity, which shall be calculated as the sum of (i) the average for the applicable calendar year of the monthly average yields of 30-year U.S. Treasury bonds published by the Board of Governors of the Federal Reserve System in its weekly H.15 Statistical Release or successor publication; and (ii) 580 basis points, including a revenue conversion factor calculated to recover or refund all additional income taxes that may be payable or receivable as a result of that return.
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When an electric utility creates a regulatory asset
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| under the provisions of this paragraph (1) of subsection (h), the costs are recovered over a period during which customers also receive a benefit, which is in the public interest. Accordingly, it is the intent of the General Assembly that an electric utility that elects to create a regulatory asset under the provisions of this paragraph (1) shall recover all of the associated costs, including, but not limited to, its cost of capital as set forth in this paragraph (1). After the Commission has approved the prudence and reasonableness of the costs that comprise the regulatory asset, the electric utility shall be permitted to recover all such costs, and the value and recoverability through rates of the associated regulatory asset shall not be limited, altered, impaired, or reduced. To enable the financing of the incremental capital expenditures, including regulatory assets, for electric utilities that serve less than 3,000,000 retail customers but more than 500,000 retail customers in the State, the utility's actual year-end capital structure that includes a common equity ratio, excluding goodwill, of up to and including 50% of the total capital structure shall be deemed reasonable and used to set rates.
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(2) The utility, at its election, may recover all of
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| the costs as part of a filing for a general increase in rates under Article IX of this Act, as part of an annual filing to update a performance-based formula rate under subsection (d) of Section 16-108.5 of this Act, or through an automatic adjustment clause tariff, provided that nothing in this paragraph (2) permits the double recovery of such costs from customers. If the utility elects to recover the costs it incurs under subsections (b) and (c) through an automatic adjustment clause tariff, the utility may file its proposed tariff together with the tariff it files under subsection (b) of this Section or at a later time. The proposed tariff shall provide for an annual reconciliation, less any deferred taxes related to the reconciliation, with interest at an annual rate of return equal to the utility's weighted average cost of capital as calculated under paragraph (1) of this subsection (h), including a revenue conversion factor calculated to recover or refund all additional income taxes that may be payable or receivable as a result of that return, of the revenue requirement reflected in rates for each calendar year, beginning with the calendar year in which the utility files its automatic adjustment clause tariff under this subsection (h), with what the revenue requirement would have been had the actual cost information for the applicable calendar year been available at the filing date. The Commission shall review the proposed tariff and may make changes to the tariff that are consistent with this Section and with the Commission's authority under Article IX of this Act, subject to notice and hearing. Following notice and hearing, the Commission shall issue an order approving, or approving with modification, such tariff no later than 240 days after the utility files its tariff.
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(i) An electric utility shall recover from its retail customers, on a volumetric basis, all of the costs of the rebates made under a tariff or tariffs placed into effect under subsection (e) of this Section, including, but not limited to, the value of the rebates and all costs incurred by the utility to comply with and implement subsection (e) of this Section, consistent with the following provisions:
(1) The utility may defer a portion of its costs as a
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| regulatory asset. The Commission shall determine the portion that may be appropriately deferred as a regulatory asset. Factors that the Commission shall consider in determining the portion of costs that shall be deferred as a regulatory asset include, but are not limited to: (i) whether and the extent to which a cost effectively deferred or avoided other distribution system operating costs or capital expenditures; (ii) the extent to which a cost provides environmental benefits; (iii) the extent to which a cost improves system reliability or resilience; (iv) the electric utility's distribution system plan developed pursuant to Section 16-105.17 of this Act; (v) the extent to which a cost advances equity principles; and (vi) such other factors as the Commission deems appropriate. The remainder of costs shall be deemed an operating expense and shall be recoverable if found prudent and reasonable by the Commission.
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The total costs deferred as a regulatory asset shall
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| be amortized over a 15-year period. The unamortized balance shall be recognized as of December 31 for a given year. The utility shall also earn a return on the total of the unamortized balance of the regulatory assets, less any deferred taxes related to the unamortized balance, at an annual rate equal to the utility's weighted average cost of capital that includes, based on a year-end capital structure, the utility's actual cost of debt for the applicable calendar year and a cost of equity, which shall be calculated as the sum of: (I) the average for the applicable calendar year of the monthly average yields of 30-year U.S. Treasury bonds published by the Board of Governors of the Federal Reserve System in its weekly H.15 Statistical Release or successor publication; and (II) 580 basis points, including a revenue conversion factor calculated to recover or refund all additional income taxes that may be payable or receivable as a result of that return.
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(2) The utility may recover all of the costs through
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| an automatic adjustment clause tariff, on a volumetric basis. The utility may file its proposed cost-recovery tariff together with the tariff it files under subsection (e) of this Section or at a later time. The proposed tariff shall provide for an annual reconciliation, less any deferred taxes related to the reconciliation, with interest at an annual rate of return equal to the utility's weighted average cost of capital as calculated under paragraph (1) of this subsection (i), including a revenue conversion factor calculated to recover or refund all additional income taxes that may be payable or receivable as a result of that return, of the revenue requirement reflected in rates for each calendar year, beginning with the calendar year in which the utility files its automatic adjustment clause tariff under this subsection (i), with what the revenue requirement would have been had the actual cost information for the applicable calendar year been available at the filing date. The Commission shall review the proposed tariff and may make changes to the tariff that are consistent with this Section and with the Commission's authority under Article IX of this Act, subject to notice and hearing. Following notice and hearing, the Commission shall issue an order approving, or approving with modification, such tariff no later than 240 days after the utility files its tariff.
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(j) No later than 90 days after the Commission enters an order, or order on rehearing, whichever is later, approving an electric utility's proposed tariff under this Section, the electric utility shall provide notice of the availability of rebates under this Section.
(Source: P.A. 102-662, eff. 9-15-21; 102-1031, eff. 5-27-22.)
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(220 ILCS 5/16-108)
Sec. 16-108. Recovery of costs associated with the
provision of delivery and other services. (a) An electric utility shall file a delivery services
tariff with the Commission at least 210 days prior to the date
that it is required to begin offering such services pursuant
to this Act. An electric utility shall provide the components
of delivery services that are subject to the jurisdiction of
the Federal Energy Regulatory Commission at the same prices,
terms and conditions set forth in its applicable tariff as
approved or allowed into effect by that Commission. The
Commission shall otherwise have the authority pursuant to Article IX to review,
approve, and modify the prices, terms and conditions of those
components of delivery services not subject to the
jurisdiction of the Federal Energy Regulatory Commission,
including the authority to determine the extent to which such
delivery services should be offered on an unbundled basis. In making any such
determination the Commission shall consider, at a minimum, the effect of
additional unbundling on (i) the objective of just and reasonable rates, (ii)
electric utility employees, and (iii) the development of competitive markets
for electric energy services in Illinois.
(b) The Commission shall enter an order approving, or
approving as modified, the delivery services tariff no later
than 30 days prior to the date on which the electric utility
must commence offering such services. The Commission may
subsequently modify such tariff pursuant to this Act.
(c) The electric utility's
tariffs shall define the classes of its customers for purposes
of delivery services charges. Delivery services shall be priced and made
available to all retail customers electing delivery services in each such class
on a nondiscriminatory basis regardless of whether the retail customer chooses
the electric utility, an affiliate of the electric utility, or another entity
as its supplier of electric power and energy. Charges for delivery services
shall be cost based,
and shall allow the electric utility to recover the costs of
providing delivery services through its charges to its
delivery service customers that use the facilities and
services associated with such costs.
Such costs shall include the
costs of owning, operating and maintaining transmission and
distribution facilities. The Commission shall also be
authorized to consider whether, and if so to what extent, the
following costs are appropriately included in the electric
utility's delivery services rates: (i) the costs of that
portion of generation facilities used for the production and
absorption of reactive power in order that retail customers
located in the electric utility's service area can receive
electric power and energy from suppliers other than the
electric utility, and (ii) the costs associated with the use
and redispatch of generation facilities to mitigate
constraints on the transmission or distribution system in
order that retail customers located in the electric utility's
service area can receive electric power and energy from
suppliers other than the electric utility. Nothing in this
subsection shall be construed as directing the Commission to
allocate any of the costs described in (i) or (ii) that are
found to be appropriately included in the electric utility's
delivery services rates to any particular customer group or
geographic area in setting delivery services rates.
(d) The Commission shall establish charges, terms and
conditions for delivery services that are just and reasonable
and shall take into account customer impacts when establishing
such charges. In establishing charges, terms and conditions
for delivery services, the Commission shall take into account
voltage level differences. A retail customer shall have the
option to request to purchase electric service at any delivery
service voltage reasonably and technically feasible from the
electric facilities serving that customer's premises provided
that there are no significant adverse impacts upon system
reliability or system efficiency. A retail customer shall
also have the option to request to purchase electric service
at any point of delivery that is reasonably and technically
feasible provided that there are no significant adverse
impacts on system reliability or efficiency. Such requests
shall not be unreasonably denied.
(e) Electric utilities shall recover the costs of
installing, operating or maintaining facilities for the
particular benefit of one or more delivery services customers,
including without limitation any costs incurred in complying
with a customer's request to be served at a different voltage
level, directly from the retail customer or customers for
whose benefit the costs were incurred, to the extent such
costs are not recovered through the charges referred to in
subsections (c) and (d) of this Section.
(f) An electric utility shall be entitled but not
required to implement transition charges in conjunction with
the offering of delivery services pursuant to Section 16-104.
If an electric utility implements transition charges, it shall implement such
charges for all delivery services customers and for all customers described in
subsection (h), but shall not implement transition charges for power and
energy that a retail customer takes from cogeneration or self-generation
facilities located on that retail customer's premises, if such facilities meet
the following criteria:
(i) the cogeneration or self-generation facilities |
| serve a single retail customer and are located on that retail customer's premises (for purposes of this subparagraph and subparagraph (ii), an industrial or manufacturing retail customer and a third party contractor that is served by such industrial or manufacturing customer through such retail customer's own electrical distribution facilities under the circumstances described in subsection (vi) of the definition of "alternative retail electric supplier" set forth in Section 16-102, shall be considered a single retail customer);
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(ii) the cogeneration or self-generation facilities
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| either (A) are sized pursuant to generally accepted engineering standards for the retail customer's electrical load at that premises (taking into account standby or other reliability considerations related to that retail customer's operations at that site) or (B) if the facility is a cogeneration facility located on the retail customer's premises, the retail customer is the thermal host for that facility and the facility has been designed to meet that retail customer's thermal energy requirements resulting in electrical output beyond that retail customer's electrical demand at that premises, comply with the operating and efficiency standards applicable to "qualifying facilities" specified in title 18 Code of Federal Regulations Section 292.205 as in effect on the effective date of this amendatory Act of 1999;
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(iii) the retail customer on whose premises the
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| facilities are located either has an exclusive right to receive, and corresponding obligation to pay for, all of the electrical capacity of the facility, or in the case of a cogeneration facility that has been designed to meet the retail customer's thermal energy requirements at that premises, an identified amount of the electrical capacity of the facility, over a minimum 5-year period; and
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(iv) if the cogeneration facility is sized for the
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| retail customer's thermal load at that premises but exceeds the electrical load, any sales of excess power or energy are made only at wholesale, are subject to the jurisdiction of the Federal Energy Regulatory Commission, and are not for the purpose of circumventing the provisions of this subsection (f).
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If a generation facility located at a retail customer's premises does not meet
the above criteria, an electric utility implementing
transition charges shall implement a transition charge until December 31, 2006
for any power and energy taken by such retail customer from such facility as if
such power and energy had been delivered by the electric utility. Provided,
however, that an industrial retail customer that is taking power from a
generation facility that does not meet the above criteria but that is located
on such customer's premises will not be subject to a transition charge for the
power and energy taken by such retail customer from such generation facility if
the facility does not serve any other retail customer and either was installed
on behalf of the customer and for its own use prior to January 1, 1997, or is
both predominantly fueled by byproducts of such customer's manufacturing
process at such premises and sells or offers an average of 300 megawatts or
more of electricity produced from such generation facility into the wholesale
market.
Such charges
shall be calculated as provided in Section
16-102, and shall be collected
on each kilowatt-hour delivered under a
delivery services tariff to a retail customer from the date
the customer first takes delivery services until December 31,
2006 except as provided in subsection (h) of this Section.
Provided, however, that an electric utility, other than an electric utility
providing service to at least 1,000,000 customers in this State on January 1,
1999,
shall be entitled to petition for
entry of an order by the Commission authorizing the electric utility to
implement transition charges for an additional period ending no later than
December 31, 2008. The electric utility shall file its petition with
supporting evidence no earlier than 16 months, and no later than 12 months,
prior to December 31, 2006. The Commission shall hold a hearing on the
electric utility's petition and shall enter its order no later than 8 months
after the petition is filed. The Commission shall determine whether and to
what extent the electric utility shall be authorized to implement transition
charges for an additional period. The Commission may authorize the electric
utility to implement transition charges for some or all of the additional
period, and shall determine the mitigation factors to be used in implementing
such transition charges; provided, that the Commission shall not authorize
mitigation factors less than 110% of those in effect during the 12 months ended
December 31, 2006. In making its determination, the Commission shall consider
the following factors: the necessity to implement transition charges for an
additional period in order to maintain the financial integrity of the electric
utility; the prudence of the electric utility's actions in reducing its costs
since the effective date of this amendatory Act of 1997; the ability of the
electric utility to provide safe, adequate and reliable service to retail
customers in its service area; and the impact on competition of allowing the
electric utility to implement transition charges for the additional period.
(g) The electric utility shall file tariffs that
establish the transition charges to be paid by each class of
customers to the electric utility in conjunction with the
provision of delivery services. The electric utility's tariffs
shall define the classes of its customers for purposes of
calculating transition charges. The electric utility's tariffs
shall provide for the calculation of transition charges on a
customer-specific basis for any 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 electrical demands equals or exceeds 3.0 megawatts for
electric utilities having more than 1,000,000 customers, and
for other electric utilities for any customer that has an
average monthly maximum electrical demand on the electric
utility's system of one megawatt or more, and (A) for which
there exists data on the customer's usage during the 3 years
preceding the date that the customer became eligible to take
delivery services, or (B) for which there does not exist data
on the customer's usage during the 3 years preceding the date
that the customer became eligible to take delivery services,
if in the electric utility's reasonable judgment there exists
comparable usage information or a sufficient basis to develop
such information, and further provided that the electric
utility can require customers for which an individual
calculation is made to sign contracts that set forth the
transition charges to be paid by the customer to the electric
utility pursuant to the tariff.
(h) An electric utility shall also be entitled to file
tariffs that allow it to collect transition charges from
retail customers in the electric utility's service area that
do not take delivery services but that take electric power or
energy from an alternative retail electric supplier or from an
electric utility other than the electric utility in whose
service area the customer is located. Such charges shall be
calculated, in accordance with the definition of transition
charges in Section 16-102, for the period of time that the
customer would be obligated to pay transition charges if it
were taking delivery services, except that no deduction for
delivery services revenues shall be made in such calculation,
and usage data from the customer's class shall be used where
historical usage data is not available for the individual
customer. The customer shall be obligated to pay such charges
on a lump sum basis on or before the date on which the
customer commences to take service from the alternative retail
electric supplier or other electric utility, provided, that
the electric utility in whose service area the customer is
located shall offer the customer the option of signing a
contract pursuant to which the customer pays such charges
ratably over the period in which the charges would otherwise
have applied.
(i) An electric utility shall be entitled to add to the
bills of delivery services customers charges pursuant to
Sections 9-221, 9-222 (except as provided in Section 9-222.1), and Section
16-114 of this Act, Section 5-5 of the Electricity Infrastructure Maintenance
Fee Law, Section 6-5 of the Renewable Energy, Energy Efficiency, and Coal
Resources Development Law of 1997, and Section 13 of the Energy Assistance Act.
(i-5) An electric utility required to impose the Coal to Solar and Energy Storage Initiative Charge provided for in subsection (c-5) of Section 1-75 of the Illinois Power Agency Act shall add such charge to the bills of its delivery services customers pursuant to the terms of a tariff conforming to the requirements of subsection (c-5) of Section 1-75 of the Illinois Power Agency Act and this subsection (i-5) and filed with and approved by the Commission. The electric utility shall file its proposed tariff with the Commission on or before July 1, 2022 to be effective, after review and approval or modification by the Commission, beginning January 1, 2023. On or before December 1, 2022, the Commission shall review the electric utility's proposed tariff, including by conducting a docketed proceeding if deemed necessary by the Commission, and shall approve the proposed tariff or direct the electric utility to make modifications the Commission finds necessary for the tariff to conform to the requirements of subsection (c-5) of Section 1-75 of the Illinois Power Agency Act and this subsection (i-5). The electric utility's tariff shall provide for imposition of the Coal to Solar and Energy Storage Initiative Charge on a per-kilowatthour basis to all kilowatthours delivered by the electric utility to its delivery services customers. The tariff shall provide for the calculation of the Coal to Solar and Energy Storage Initiative Charge to be in effect for the year beginning January 1, 2023 and each year beginning January 1 thereafter, sufficient to collect the electric utility's estimated payment obligations for the delivery year beginning the following June 1 under contracts for purchase of renewable energy credits entered into pursuant to subsection (c-5) of Section 1-75 of the Illinois Power Agency Act and the obligations of the Department of Commerce and Economic Opportunity, or any successor department or agency, which for purposes of this subsection (i-5) shall be referred to as the Department, to make grant payments during such delivery year from the Coal to Solar and Energy Storage Initiative Fund pursuant to grant contracts entered into pursuant to subsection (c-5) of Section 1-75 of the Illinois Power Agency Act, and using the electric utility's kilowatthour deliveries to its delivery services customers during the delivery year ended May 31 of the preceding calendar year. On or before November 1 of each year beginning November 1, 2022, the Department shall notify the electric utilities of the amount of the Department's estimated obligations for grant payments during the delivery year beginning the following June 1 pursuant to grant contracts entered into pursuant to subsection (c-5) of Section 1-75 of the Illinois Power Agency Act; and each electric utility shall incorporate in the calculation of its Coal to Solar and Energy Storage Initiative Charge the fractional portion of the Department's estimated obligations equal to the electric utility's kilowatthour deliveries to its delivery services customers in the delivery year ended the preceding May 31 divided by the aggregate deliveries of both electric utilities to delivery services customers in such delivery year. The electric utility shall remit on a monthly basis to the State Treasurer, for deposit in the Coal to Solar and Energy Storage Initiative Fund provided for in subsection (c-5) of Section 1-75 of the Illinois Power Agency Act, the electric utility's collections of the Coal to Solar and Energy Storage Initiative Charge estimated to be needed by the Department for grant payments pursuant to grant contracts entered into pursuant to subsection (c-5) of Section 1-75 of the Illinois Power Agency Act. The initial charge under the electric utility's tariff shall be effective for kilowatthours delivered beginning January 1, 2023, and thereafter shall be revised to be effective January 1, 2024 and each January 1 thereafter, based on the payment obligations for the delivery year beginning the following June 1. The tariff shall provide for the electric utility to make an annual filing with the Commission on or before November 15 of each year, beginning in 2023, setting forth the Coal to Solar and Energy Storage Initiative Charge to be in effect for the year beginning the following January 1. The electric utility's tariff shall also provide that the electric utility shall make a filing with the Commission on or before August 1 of each year beginning in 2024 setting forth a reconciliation, for the delivery year ended the preceding May 31, of the electric utility's collections of the Coal to Solar and Energy Storage Initiative Charge against actual payments for renewable energy credits pursuant to contracts entered into, and the actual grant payments by the Department pursuant to grant contracts entered into, pursuant to subsection (c-5) of Section 1-75 of the Illinois Power Agency Act. The tariff shall provide that any excess or shortfall of collections to payments shall be deducted from or added to, on a per-kilowatthour basis, the Coal to Solar and Energy Storage Initiative Charge, over the 6-month period beginning October 1 of that calendar year.
(j) If a retail customer that obtains electric power and
energy from cogeneration or self-generation facilities
installed for its own use on or before January 1, 1997,
subsequently takes service from an alternative retail electric
supplier or an electric utility other than the electric
utility in whose service area the customer is located for any
portion of the customer's electric power and energy
requirements formerly obtained from those facilities (including that amount
purchased from the utility in lieu of such generation and not as standby power
purchases, under a cogeneration displacement tariff in effect as of the
effective date of this amendatory Act of 1997), the
transition charges otherwise applicable pursuant to subsections (f), (g), or
(h) of this Section shall not be applicable
in any year to that portion of the customer's electric power
and energy requirements formerly obtained from those
facilities, provided, that for purposes of this subsection
(j), such portion shall not exceed the average number of
kilowatt-hours per year obtained from the cogeneration or
self-generation facilities during the 3 years prior to the
date on which the customer became eligible for delivery
services, except as provided in subsection (f) of Section
16-110.
(k) The electric utility shall be entitled to recover through tariffed charges all of the costs associated with the purchase of zero emission credits from zero emission facilities to meet the requirements of subsection (d-5) of Section 1-75 of the Illinois Power Agency Act and all of the costs associated with the purchase of carbon mitigation credits from carbon-free energy resources to meet the requirements of subsection (d-10) of Section 1-75 of the Illinois Power Agency Act. Such costs shall include the costs of procuring the zero emission credits and carbon mitigation credits from carbon-free energy resources, as well as the reasonable costs that the utility incurs as part of the procurement processes and to implement and comply with plans and processes approved by the Commission under subsections (d-5) and (d-10). The costs shall be allocated across all retail customers through a single, uniform cents per kilowatt-hour charge applicable to all retail customers, which shall appear as a separate line item on each customer's bill. Beginning June 1, 2017, the electric utility shall be entitled to recover through tariffed charges all of the costs associated with the purchase of renewable energy resources to meet the renewable energy resource standards of subsection (c) of Section 1-75 of the Illinois Power Agency Act, under procurement plans as approved in accordance with that Section and Section 16-111.5 of this Act. Such costs shall include the costs of procuring the renewable energy resources, as well as the reasonable costs that the utility incurs as part of the procurement processes and to implement and comply with plans and processes approved by the Commission under such Sections. The costs associated with the purchase of renewable energy resources shall be allocated across all retail customers in proportion to the amount of renewable energy resources the utility procures for such customers through a single, uniform cents per kilowatt-hour charge applicable to such retail customers, which shall appear as a separate line item on each such customer's bill. The credits, costs, and penalties associated with the self-direct renewable portfolio standard compliance program described in subparagraph (R) of paragraph (1) of subsection (c) of Section 1-75 of the Illinois Power Agency Act shall be allocated to approved eligible self-direct customers by the utility in a cents per kilowatt-hour credit, cost, or penalty, which shall appear as a separate line item on each such customer's bill.
Notwithstanding whether the Commission has approved the initial long-term renewable resources procurement plan as of June 1, 2017, an electric utility shall place new tariffed charges into effect beginning with the June 2017 monthly billing period, to the extent practicable, to begin recovering the costs of procuring renewable energy resources, as those charges are calculated under the limitations described in subparagraph (E) of paragraph (1) of subsection (c) of Section 1-75 of the Illinois Power Agency Act. Notwithstanding the date on which the utility places such new tariffed charges into effect, the utility shall be permitted to collect the charges under such tariff as if the tariff had been in effect beginning with the first day of the June 2017 monthly billing period. For the delivery years commencing June 1, 2017, June 1, 2018, June 1, 2019, and each delivery year thereafter, the electric utility shall deposit into a separate interest bearing account of a financial institution the monies collected under the tariffed charges. Money collected from customers for the procurement of renewable energy resources in a given delivery year may be spent by the utility for the procurement of renewable resources over any of the following 5 delivery years, after which unspent money shall be credited back to retail customers. The electric utility shall spend all money collected in earlier delivery years that has not yet been returned to customers, first, before spending money collected in later delivery years. Any interest earned shall be credited back to retail customers under the reconciliation proceeding provided for in this subsection (k), provided that the electric utility shall first be reimbursed from the interest for the administrative costs that it incurs to administer and manage the account. Any taxes due on the funds in the account, or interest earned on it, will be paid from the account or, if insufficient monies are available in the account, from the monies collected under the tariffed charges to recover the costs of procuring renewable energy resources. Monies deposited in the account shall be subject to the review, reconciliation, and true-up process described in this subsection (k) that is applicable to the funds collected and costs incurred for the procurement of renewable energy resources.
The electric utility shall be entitled to recover all of the costs identified in this subsection (k) through automatic adjustment clause tariffs applicable to all of the utility's retail customers that allow the electric utility to adjust its tariffed charges consistent with this subsection (k). The determination as to whether any excess funds were collected during a given delivery year for the purchase of renewable energy resources, and the crediting of any excess funds back to retail customers, shall not be made until after the close of the delivery year, which will ensure that the maximum amount of funds is available to implement the approved long-term renewable resources procurement plan during a given delivery year. The amount of excess funds eligible to be credited back to retail customers shall be reduced by an amount equal to the payment obligations required by any contracts entered into by an electric utility under contracts described in subsection (b) of Section 1-56 and subsection (c) of Section 1-75 of the Illinois Power Agency Act, even if such payments have not yet been made and regardless of the delivery year in which those payment obligations were incurred. Notwithstanding anything to the contrary, including in tariffs authorized by this subsection (k) in effect before the effective date of this amendatory Act of the 102nd General Assembly, all unspent funds as of May 31, 2021, excluding any funds credited to customers during any utility billing cycle that commences prior to the effective date of this amendatory Act of the 102nd General Assembly, shall remain in the utility account and shall on a first in, first out basis be used toward utility payment obligations under contracts described in subsection (b) of Section 1-56 and subsection (c) of Section 1-75 of the Illinois Power Agency Act. The electric utility's collections under such automatic adjustment clause tariffs to recover the costs of renewable energy resources, zero emission credits from zero emission facilities, and carbon mitigation credits from carbon-free energy resources shall be subject to separate annual review, reconciliation, and true-up against actual costs by the Commission under a procedure that shall be specified in the electric utility's automatic adjustment clause tariffs and that shall be approved by the Commission in connection with its approval of such tariffs. The procedure shall provide that any difference between the electric utility's collections for zero emission credits and carbon mitigation credits under the automatic adjustment charges for an annual period and the electric utility's actual costs of zero emission credits from zero emission facilities and carbon mitigation credits from carbon-free energy resources for that same annual period shall be refunded to or collected from, as applicable, the electric utility's retail customers in subsequent periods.
Nothing in this subsection (k) is intended to affect, limit, or change the right of the electric utility to recover the costs associated with the procurement of renewable energy resources for periods commencing before, on, or after June 1, 2017, as otherwise provided in the Illinois Power Agency Act.
The funding available under this subsection (k), if any, for the programs described under subsection (b) of Section 1-56 of the Illinois Power Agency Act shall not reduce the amount of funding for the programs described in subparagraph (O) of paragraph (1) of subsection (c) of Section 1-75 of the Illinois Power Agency Act. If funding is available under this subsection (k) for programs described under subsection (b) of Section 1-56 of the Illinois Power Agency Act, then the long-term renewable resources plan shall provide for the Agency to procure contracts in an amount that does not exceed the funding, and the contracts approved by the Commission shall be executed by the applicable utility or utilities.
(l) A utility that has terminated any contract executed under subsection (d-5) or (d-10) of Section 1-75 of the Illinois Power Agency Act shall be entitled to recover any remaining balance associated with the purchase of zero emission credits prior to such termination, and such utility shall also apply a credit to its retail customer bills in the event of any over-collection.
(m)(1) An electric utility that recovers its costs of procuring zero emission credits from zero emission facilities through a cents-per-kilowatthour charge under subsection (k) of this Section shall be subject to the requirements of this subsection (m). Notwithstanding anything to the contrary, such electric utility shall, beginning on April 30, 2018, and each April 30 thereafter until April 30, 2026, calculate whether any reduction must be applied to such cents-per-kilowatthour charge that is paid by retail customers of the electric utility that have opted out of subsections (a) through (j) of Section 8-103B of this Act under subsection (l) of Section 8-103B. Such charge shall be reduced for such customers for the next delivery year commencing on June 1 based on the amount necessary, if any, to limit the annual estimated average net increase for the prior calendar year due to the future energy investment costs to no more than 1.3% of 5.98 cents per kilowatt-hour, which is the average amount paid per kilowatthour for electric service during the year ending December 31, 2015 by Illinois industrial retail customers, as reported to the Edison Electric Institute.
The calculations required by this subsection (m) shall be made only once for each year, and no subsequent rate impact determinations shall be made.
(2) For purposes of this Section, "future energy investment costs" shall be calculated by subtracting the cents-per-kilowatthour charge identified in subparagraph (A) of this paragraph (2) from the sum of the cents-per-kilowatthour charges identified in subparagraph (B) of this paragraph (2):
(A) The cents-per-kilowatthour charge identified in
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| the electric utility's tariff placed into effect under Section 8-103 of the Public Utilities Act that, on December 1, 2016, was applicable to those retail customers that have opted out of subsections (a) through (j) of Section 8-103B of this Act under subsection (l) of Section 8-103B.
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(B) The sum of the following cents-per-kilowatthour
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| charges applicable to those retail customers that have opted out of subsections (a) through (j) of Section 8-103B of this Act under subsection (l) of Section 8-103B, provided that if one or more of the following charges has been in effect and applied to such customers for more than one calendar year, then each charge shall be equal to the average of the charges applied over a period that commences with the calendar year ending December 31, 2017 and ends with the most recently completed calendar year prior to the calculation required by this subsection (m):
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(i) the cents-per-kilowatthour charge to recover
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| the costs incurred by the utility under subsection (d-5) of Section 1-75 of the Illinois Power Agency Act, adjusted for any reductions required under this subsection (m); and
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(ii) the cents-per-kilowatthour charge to recover
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| the costs incurred by the utility under Section 16-107.6 of the Public Utilities Act.
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If no charge was applied for a given calendar year
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| under item (i) or (ii) of this subparagraph (B), then the value of the charge for that year shall be zero.
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(3) If a reduction is required by the calculation performed under this subsection (m), then the amount of the reduction shall be multiplied by the number of years reflected in the averages calculated under subparagraph (B) of paragraph (2) of this subsection (m). Such reduction shall be applied to the cents-per-kilowatthour charge that is applicable to those retail customers that have opted out of subsections (a) through (j) of Section 8-103B of this Act under subsection (l) of Section 8-103B beginning with the next delivery year commencing after the date of the calculation required by this subsection (m).
(4) The electric utility shall file a notice with the Commission on May 1 of 2018 and each May 1 thereafter until May 1, 2026 containing the reduction, if any, which must be applied for the delivery year which begins in the year of the filing. The notice shall contain the calculations made pursuant to this Section. By October 1 of each year beginning in 2018, each electric utility shall notify the Commission if it appears, based on an estimate of the calculation required in this subsection (m), that a reduction will be required in the next year.
(Source: P.A. 102-662, eff. 9-15-21.)
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(220 ILCS 5/16-108.5) Sec. 16-108.5. Infrastructure investment and modernization; regulatory reform. (a) (Blank). (b) For purposes of this Section, "participating utility" means an electric utility or a combination utility serving more than 1,000,000 customers in Illinois that voluntarily elects and commits to undertake (i) the infrastructure investment program consisting of the commitments and obligations described in this subsection (b) and (ii) the customer assistance program consisting of the commitments and obligations described in subsection (b-10) of this Section, notwithstanding any other provisions of this Act and without obtaining any approvals from the Commission or any other agency other than as set forth in this Section, regardless of whether any such approval would otherwise be required. "Combination utility" means a utility that, as of January 1, 2011, provided electric service to at least one million retail customers in Illinois and gas service to at least 500,000 retail customers in Illinois. A participating utility shall recover the expenditures made under the infrastructure investment program through the ratemaking process, including, but not limited to, the performance-based formula rate and process set forth in this Section. During the infrastructure investment program's peak program year, a participating utility other than a combination utility shall create 2,000 full-time equivalent jobs in Illinois, and a participating utility that is a combination utility shall create 450 full-time equivalent jobs in Illinois related to the provision of electric service. These jobs shall include direct jobs, contractor positions, and induced jobs, but shall not include any portion of a job commitment, not specifically contingent on an amendatory Act of the 97th General Assembly becoming law, between a participating utility and a labor union that existed on December 30, 2011 (the effective date of Public Act 97-646) and that has not yet been fulfilled. A portion of the full-time equivalent jobs created by each participating utility shall include incremental personnel hired subsequent to December 30, 2011 (the effective date of Public Act 97-646). For purposes of this Section, "peak program year" means the consecutive 12-month period with the highest number of full-time equivalent jobs that occurs between the beginning of investment year 2 and the end of investment year 4. A participating utility shall meet one of the following commitments, as applicable: (1) Beginning no later than 180 days after a |
| participating utility other than a combination utility files a performance-based formula rate tariff pursuant to subsection (c) of this Section, or, beginning no later than January 1, 2012 if such utility files such performance-based formula rate tariff within 14 days of October 26, 2011 (the effective date of Public Act 97-616), the participating utility shall, except as provided in subsection (b-5):
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(A) over a 5-year period, invest an estimated
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| $1,300,000,000 in electric system upgrades, modernization projects, and training facilities, including, but not limited to:
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(i) distribution infrastructure improvements
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| totaling an estimated $1,000,000,000, including underground residential distribution cable injection and replacement and mainline cable system refurbishment and replacement projects;
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(ii) training facility construction or
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| upgrade projects totaling an estimated $10,000,000, provided that, at a minimum, one such facility shall be located in a municipality having a population of more than 2 million residents and one such facility shall be located in a municipality having a population of more than 150,000 residents but fewer than 170,000 residents; any such new facility located in a municipality having a population of more than 2 million residents must be designed for the purpose of obtaining, and the owner of the facility shall apply for, certification under the United States Green Building Council's Leadership in Energy Efficiency Design Green Building Rating System;
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(iii) wood pole inspection, treatment, and
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(iv) an estimated $200,000,000 for reducing
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| the susceptibility of certain circuits to storm-related damage, including, but not limited to, high winds, thunderstorms, and ice storms; improvements may include, but are not limited to, overhead to underground conversion and other engineered outcomes for circuits; the participating utility shall prioritize the selection of circuits based on each circuit's historical susceptibility to storm-related damage and the ability to provide the greatest customer benefit upon completion of the improvements; to be eligible for improvement, the participating utility's ability to maintain proper tree clearances surrounding the overhead circuit must not have been impeded by third parties; and
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(B) over a 10-year period, invest an estimated
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| $1,300,000,000 to upgrade and modernize its transmission and distribution infrastructure and in Smart Grid electric system upgrades, including, but not limited to:
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(i) additional smart meters;
(ii) distribution automation;
(iii) associated cyber secure data
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| communication network; and
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(iv) substation micro-processor relay
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(2) Beginning no later than 180 days after a
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| participating utility that is a combination utility files a performance-based formula rate tariff pursuant to subsection (c) of this Section, or, beginning no later than January 1, 2012 if such utility files such performance-based formula rate tariff within 14 days of October 26, 2011 (the effective date of Public Act 97-616), the participating utility shall, except as provided in subsection (b-5):
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(A) over a 10-year period, invest an estimated
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| $265,000,000 in electric system upgrades, modernization projects, and training facilities, including, but not limited to:
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(i) distribution infrastructure improvements
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| totaling an estimated $245,000,000, which may include bulk supply substations, transformers, reconductoring, and rebuilding overhead distribution and sub-transmission lines, underground residential distribution cable injection and replacement and mainline cable system refurbishment and replacement projects;
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(ii) training facility construction or
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| upgrade projects totaling an estimated $1,000,000; any such new facility must be designed for the purpose of obtaining, and the owner of the facility shall apply for, certification under the United States Green Building Council's Leadership in Energy Efficiency Design Green Building Rating System; and
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(iii) wood pole inspection, treatment, and
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| replacement programs; and
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(B) over a 10-year period, invest an estimated
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| $360,000,000 to upgrade and modernize its transmission and distribution infrastructure and in Smart Grid electric system upgrades, including, but not limited to:
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(i) additional smart meters;
(ii) distribution automation;
(iii) associated cyber secure data
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| communication network; and
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(iv) substation micro-processor relay
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For purposes of this Section, "Smart Grid electric system upgrades" shall have the meaning set forth in subsection (a) of Section 16-108.6 of this Act.
The investments in the infrastructure investment program described in this subsection (b) shall be incremental to the participating utility's annual capital investment program, as defined by, for purposes of this subsection (b), the participating utility's average capital spend for calendar years 2008, 2009, and 2010 as reported in the applicable Federal Energy Regulatory Commission (FERC) Form 1; provided that where one or more utilities have merged, the average capital spend shall be determined using the aggregate of the merged utilities' capital spend reported in FERC Form 1 for the years 2008, 2009, and 2010. A participating utility may add reasonable construction ramp-up and ramp-down time to the investment periods specified in this subsection (b). For each such investment period, the ramp-up and ramp-down time shall not exceed a total of 6 months.
Within 60 days after filing a tariff under subsection (c) of this Section, a participating utility shall submit to the Commission its plan, including scope, schedule, and staffing, for satisfying its infrastructure investment program commitments pursuant to this subsection (b). The submitted plan shall include a schedule and staffing plan for the next calendar year. The plan shall also include a plan for the creation, operation, and administration of a Smart Grid test bed as described in subsection (c) of Section 16-108.8. The plan need not allocate the work equally over the respective periods, but should allocate material increments throughout such periods commensurate with the work to be undertaken. No later than April 1 of each subsequent year, the utility shall submit to the Commission a report that includes any updates to the plan, a schedule for the next calendar year, the expenditures made for the prior calendar year and cumulatively, and the number of full-time equivalent jobs created for the prior calendar year and cumulatively. If the utility is materially deficient in satisfying a schedule or staffing plan, then the report must also include a corrective action plan to address the deficiency. The fact that the plan, implementation of the plan, or a schedule changes shall not imply the imprudence or unreasonableness of the infrastructure investment program, plan, or schedule. Further, no later than 45 days following the last day of the first, second, and third quarters of each year of the plan, a participating utility shall submit to the Commission a verified quarterly report for the prior quarter that includes (i) the total number of full-time equivalent jobs created during the prior quarter, (ii) the total number of employees as of the last day of the prior quarter, (iii) the total number of full-time equivalent hours in each job classification or job title, (iv) the total number of incremental employees and contractors in support of the investments undertaken pursuant to this subsection (b) for the prior quarter, and (v) any other information that the Commission may require by rule.
With respect to the participating utility's peak job commitment, if, after considering the utility's corrective action plan and compliance thereunder, the Commission enters an order finding, after notice and hearing, that a participating utility did not satisfy its peak job commitment described in this subsection (b) for reasons that are reasonably within its control, then the Commission shall also determine, after consideration of the evidence, including, but not limited to, evidence submitted by the Department of Commerce and Economic Opportunity and the utility, the deficiency in the number of full-time equivalent jobs during the peak program year due to such failure. The Commission shall notify the Department of any proceeding that is initiated pursuant to this paragraph. For each full-time equivalent job deficiency during the peak program year that the Commission finds as set forth in this paragraph, the participating utility shall, within 30 days after the entry of the Commission's order, pay $6,000 to a fund for training grants administered under Section 605-800 of the Department of Commerce and Economic Opportunity Law, which shall not be a recoverable expense.
With respect to the participating utility's investment amount commitments, if, after considering the utility's corrective action plan and compliance thereunder, the Commission enters an order finding, after notice and hearing, that a participating utility is not satisfying its investment amount commitments described in this subsection (b), then the utility shall no longer be eligible to annually update the performance-based formula rate tariff pursuant to subsection (d) of this Section. In such event, the then current rates shall remain in effect until such time as new rates are set pursuant to Article IX of this Act, subject to retroactive adjustment, with interest, to reconcile rates charged with actual costs.
If the Commission finds that a participating utility is no longer eligible to update the performance-based formula rate tariff pursuant to subsection (d) of this Section, or the performance-based formula rate is otherwise terminated, then the participating utility's voluntary commitments and obligations under this subsection (b) shall immediately terminate, except for the utility's obligation to pay an amount already owed to the fund for training grants pursuant to a Commission order.
In meeting the obligations of this subsection (b), to the extent feasible and consistent with State and federal law, the investments under the infrastructure investment program should provide employment opportunities for all segments of the population and workforce, including minority-owned and female-owned business enterprises, and shall not, consistent with State and federal law, discriminate based on race or socioeconomic status.
(b-5) Nothing in this Section shall prohibit the Commission from investigating the prudence and reasonableness of the expenditures made under the infrastructure investment program during the annual review required by subsection (d) of this Section and shall, as part of such investigation, determine whether the utility's actual costs under the program are prudent and reasonable. The fact that a participating utility invests more than the minimum amounts specified in subsection (b) of this Section or its plan shall not imply imprudence or unreasonableness.
If the participating utility finds that it is implementing its plan for satisfying the infrastructure investment program commitments described in subsection (b) of this Section at a cost below the estimated amounts specified in subsection (b) of this Section, then the utility may file a petition with the Commission requesting that it be permitted to satisfy its commitments by spending less than the estimated amounts specified in subsection (b) of this Section. The Commission shall, after notice and hearing, enter its order approving, or approving as modified, or denying each such petition within 150 days after the filing of the petition.
In no event, absent General Assembly approval, shall the capital investment costs incurred by a participating utility other than a combination utility in satisfying its infrastructure investment program commitments described in subsection (b) of this Section exceed $3,000,000,000 or, for a participating utility that is a combination utility, $720,000,000. If the participating utility's updated cost estimates for satisfying its infrastructure investment program commitments described in subsection (b) of this Section exceed the limitation imposed by this subsection (b-5), then it shall submit a report to the Commission that identifies the increased costs and explains the reason or reasons for the increased costs no later than the year in which the utility estimates it will exceed the limitation. The Commission shall review the report and shall, within 90 days after the participating utility files the report, report to the General Assembly its findings regarding the participating utility's report. If the General Assembly does not amend the limitation imposed by this subsection (b-5), then the utility may modify its plan so as not to exceed the limitation imposed by this subsection (b-5) and may propose corresponding changes to the metrics established pursuant to subparagraphs (5) through (8) of subsection (f) of this Section, and the Commission may modify the metrics and incremental savings goals established pursuant to subsection (f) of this Section accordingly.
(b-10) All participating utilities shall make contributions for an energy low-income and support program in accordance with this subsection. Beginning no later than 180 days after a participating utility files a performance-based formula rate tariff pursuant to subsection (c) of this Section, or beginning no later than January 1, 2012 if such utility files such performance-based formula rate tariff within 14 days of December 30, 2011 (the effective date of Public Act 97-646), and without obtaining any approvals from the Commission or any other agency other than as set forth in this Section, regardless of whether any such approval would otherwise be required, a participating utility other than a combination utility shall pay $10,000,000 per year for 5 years and a participating utility that is a combination utility shall pay $1,000,000 per year for 10 years to the energy low-income and support program, which is intended to fund customer assistance programs with the primary purpose being avoidance of
imminent disconnection. Such programs may include:
(1) a residential hardship program that may partner
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| with community-based organizations, including senior citizen organizations, and provides grants to low-income residential customers, including low-income senior citizens, who demonstrate a hardship;
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(2) a program that provides grants and other bill
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| payment concessions to veterans with disabilities who demonstrate a hardship and members of the armed services or reserve forces of the United States or members of the Illinois National Guard who are on active duty pursuant to an executive order of the President of the United States, an act of the Congress of the United States, or an order of the Governor and who demonstrate a hardship;
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(3) a budget assistance program that provides tools
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| and education to low-income senior citizens to assist them with obtaining information regarding energy usage and effective means of managing energy costs;
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(4) a non-residential special hardship program that
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| provides grants to non-residential customers such as small businesses and non-profit organizations that demonstrate a hardship, including those providing services to senior citizen and low-income customers; and
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(5) a performance-based assistance program that
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| provides grants to encourage residential customers to make on-time payments by matching a portion of the customer's payments or providing credits towards arrearages.
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The payments made by a participating utility pursuant to this subsection (b-10) shall not be a recoverable expense. A participating utility may elect to fund either new or existing customer assistance programs, including, but not limited to, those that are administered by the utility.
Programs that use funds that are provided by a participating utility to reduce utility bills may be implemented through tariffs that are filed with and reviewed by the Commission. If a utility elects to file tariffs with the Commission to implement all or a portion of the programs, those tariffs shall, regardless of the date actually filed, be deemed accepted and approved, and shall become effective on December 30, 2011 (the effective date of Public Act 97-646). The participating utilities whose customers benefit from the funds that are disbursed as contemplated in this Section shall file annual reports documenting the disbursement of those funds with the Commission. The Commission has the authority to audit disbursement of the funds to ensure they were disbursed consistently with this Section.
If the Commission finds that a participating utility is no longer eligible to update the performance-based formula rate tariff pursuant to subsection (d) of this Section, or the performance-based formula rate is otherwise terminated, then the participating utility's voluntary commitments and obligations under this subsection (b-10) shall immediately terminate.
(c) A participating utility may elect to recover its delivery services costs through a performance-based formula rate approved by the Commission, which shall specify the cost components that form the basis of the rate charged to customers with sufficient specificity to operate in a standardized manner and be updated annually with transparent information that reflects the utility's actual costs to be recovered during the applicable rate year, which is the period beginning with the first billing day of January and extending through the last billing day of the following December. In the event the utility recovers a portion of its costs through automatic adjustment clause tariffs on October 26, 2011 (the effective date of Public Act 97-616), the utility may elect to continue to recover these costs through such tariffs, but then these costs shall not be recovered through the performance-based formula rate. In the event the participating utility, prior to December 30, 2011 (the effective date of Public Act 97-646), filed electric delivery services tariffs with the Commission pursuant to Section 9-201 of this Act that are related to the recovery of its electric delivery services costs that are still pending on December 30, 2011 (the effective date of Public Act 97-646), the participating utility shall, at the time it files its performance-based formula rate tariff with the Commission, also file a notice of withdrawal with the Commission to withdraw the electric delivery services tariffs previously filed pursuant to Section 9-201 of this Act. Upon receipt of such notice, the Commission shall dismiss with prejudice any docket that had been initiated to investigate the electric delivery services tariffs filed pursuant to Section 9-201 of this Act, and such tariffs and the record related thereto shall not be the subject of any further hearing, investigation, or proceeding of any kind related to rates for electric delivery services.
The performance-based formula rate shall be implemented through a tariff filed with the Commission consistent with the provisions of this subsection (c) that shall be applicable to all delivery services customers. The Commission shall initiate and conduct an investigation of the tariff in a manner consistent with the provisions of this subsection (c) and the provisions of Article IX of this Act to the extent they do not conflict with this subsection (c). Except in the case where the Commission finds, after notice and hearing, that a participating utility is not satisfying its investment amount commitments under subsection (b) of this Section, the performance-based formula rate shall remain in effect at the discretion of the utility. The performance-based formula rate approved by the Commission shall do the following:
(1) Provide for the recovery of the utility's actual
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| costs of delivery services that are prudently incurred and reasonable in amount consistent with Commission practice and law. The sole fact that a cost differs from that incurred in a prior calendar year or that an investment is different from that made in a prior calendar year shall not imply the imprudence or unreasonableness of that cost or investment.
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(2) Reflect the utility's actual year-end capital
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| structure for the applicable calendar year, excluding goodwill, subject to a determination of prudence and reasonableness consistent with Commission practice and law. To enable the financing of the incremental capital expenditures, including regulatory assets, for electric utilities that serve less than 3,000,000 retail customers but more than 500,000 retail customers in the State, a participating electric utility's actual year-end capital structure that includes a common equity ratio, excluding goodwill, of up to and including 50% of the total capital structure shall be deemed reasonable and used to set rates.
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(3) Include a cost of equity, which shall be
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| calculated as the sum of the following:
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(A) the average for the applicable calendar year
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| of the monthly average yields of 30-year U.S. Treasury bonds published by the Board of Governors of the Federal Reserve System in its weekly H.15 Statistical Release or successor publication; and
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(B) 580 basis points.
At such time as the Board of Governors of the Federal
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| Reserve System ceases to include the monthly average yields of 30-year U.S. Treasury bonds in its weekly H.15 Statistical Release or successor publication, the monthly average yields of the U.S. Treasury bonds then having the longest duration published by the Board of Governors in its weekly H.15 Statistical Release or successor publication shall instead be used for purposes of this paragraph (3).
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(4) Permit and set forth protocols, subject to a
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| determination of prudence and reasonableness consistent with Commission practice and law, for the following:
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(A) recovery of incentive compensation expense
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| that is based on the achievement of operational metrics, including metrics related to budget controls, outage duration and frequency, safety, customer service, efficiency and productivity, and environmental compliance. Incentive compensation expense that is based on net income or an affiliate's earnings per share shall not be recoverable under the performance-based formula rate;
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(B) recovery of pension and other post-employment
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| benefits expense, provided that such costs are supported by an actuarial study;
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(C) recovery of severance costs, provided that if
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| the amount is over $3,700,000 for a participating utility that is a combination utility or $10,000,000 for a participating utility that serves more than 3 million retail customers, then the full amount shall be amortized consistent with subparagraph (F) of this paragraph (4);
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(D) investment return at a rate equal to the
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| utility's weighted average cost of long-term debt, on the pension assets as, and in the amount, reported in Account 186 (or in such other Account or Accounts as such asset may subsequently be recorded) of the utility's most recently filed FERC Form 1, net of deferred tax benefits;
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(E) recovery of the expenses related to the
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| Commission proceeding under this subsection (c) to approve this performance-based formula rate and initial rates or to subsequent proceedings related to the formula, provided that the recovery shall be amortized over a 3-year period; recovery of expenses related to the annual Commission proceedings under subsection (d) of this Section to review the inputs to the performance-based formula rate shall be expensed and recovered through the performance-based formula rate;
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(F) amortization over a 5-year period of the full
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| amount of each charge or credit that exceeds $3,700,000 for a participating utility that is a combination utility or $10,000,000 for a participating utility that serves more than 3 million retail customers in the applicable calendar year and that relates to a workforce reduction program's severance costs, changes in accounting rules, changes in law, compliance with any Commission-initiated audit, or a single storm or other similar expense, provided that any unamortized balance shall be reflected in the rate base. For purposes of this subparagraph (F), 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 to environmental matters, or in the interpretation or application thereof by any governmental authority occurring after October 26, 2011 (the effective date of Public Act 97-616);
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(G) recovery of existing regulatory assets over
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| the periods previously authorized by the Commission;
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(H) historical weather normalized billing
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(I) allocation methods for common costs.
(5) Provide that if the participating utility's
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| earned rate of return on common equity related to the provision of delivery services for the prior rate year (calculated using costs and capital structure approved by the Commission as provided in subparagraph (2) of this subsection (c), consistent with this Section, in accordance with Commission rules and orders, including, but not limited to, adjustments for goodwill, and after any Commission-ordered disallowances and taxes) is more than 50 basis points higher than the rate of return on common equity calculated pursuant to paragraph (3) of this subsection (c) (after adjusting for any penalties to the rate of return on common equity applied pursuant to the performance metrics provision of subsection (f) of this Section), then the participating utility shall apply a credit through the performance-based formula rate that reflects an amount equal to the value of that portion of the earned rate of return on common equity that is more than 50 basis points higher than the rate of return on common equity calculated pursuant to paragraph (3) of this subsection (c) (after adjusting for any penalties to the rate of return on common equity applied pursuant to the performance metrics provision of subsection (f) of this Section) for the prior rate year, adjusted for taxes. If the participating utility's earned rate of return on common equity related to the provision of delivery services for the prior rate year (calculated using costs and capital structure approved by the Commission as provided in subparagraph (2) of this subsection (c), consistent with this Section, in accordance with Commission rules and orders, including, but not limited to, adjustments for goodwill, and after any Commission-ordered disallowances and taxes) is more than 50 basis points less than the return on common equity calculated pursuant to paragraph (3) of this subsection (c) (after adjusting for any penalties to the rate of return on common equity applied pursuant to the performance metrics provision of subsection (f) of this Section), then the participating utility shall apply a charge through the performance-based formula rate that reflects an amount equal to the value of that portion of the earned rate of return on common equity that is more than 50 basis points less than the rate of return on common equity calculated pursuant to paragraph (3) of this subsection (c) (after adjusting for any penalties to the rate of return on common equity applied pursuant to the performance metrics provision of subsection (f) of this Section) for the prior rate year, adjusted for taxes.
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(6) Provide for an annual reconciliation, as
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| described in subsection (d) of this Section, with interest, of the revenue requirement reflected in rates for each calendar year, beginning with the calendar year in which the utility files its performance-based formula rate tariff pursuant to subsection (c) of this Section, with what the revenue requirement would have been had the actual cost information for the applicable calendar year been available at the filing date.
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The utility shall file, together with its tariff, final data based on its most recently filed FERC Form 1, plus projected plant additions and correspondingly updated depreciation reserve and expense for the calendar year in which the tariff and data are filed, that shall populate the performance-based formula rate and set the initial delivery services rates under the formula. For purposes of this Section, "FERC Form 1" means the Annual Report of Major Electric Utilities, Licensees and Others that electric utilities are required to file with the Federal Energy Regulatory Commission under the Federal Power Act, Sections 3, 4(a), 304 and 209, modified as necessary to be consistent with 83 Ill. Adm. Code Part 415 as of May 1, 2011. Nothing in this Section is intended to allow costs that are not otherwise recoverable to be recoverable by virtue of inclusion in FERC Form 1.
After the utility files its proposed performance-based formula rate structure and protocols and initial rates, the Commission shall initiate a docket to review the filing. The Commission shall enter an order approving, or approving as modified, the performance-based formula rate, including the initial rates, as just and reasonable within 270 days after the date on which the tariff was filed, or, if the tariff is filed within 14 days after October 26, 2011 (the effective date of Public Act 97-616), then by May 31, 2012. Such review shall be based on the same evidentiary standards, including, but not limited to, those concerning the prudence and reasonableness of the costs incurred by the utility, the Commission applies in a hearing to review a filing for a general increase in rates under Article IX of this Act. The initial rates shall take effect within 30 days after the Commission's order approving the performance-based formula rate tariff.
Until such time as the Commission approves a different rate design and cost allocation pursuant to subsection (e) of this Section, rate design and cost allocation across customer classes shall be consistent with the Commission's most recent order regarding the participating utility's request for a general increase in its delivery services rates.
Subsequent changes to the performance-based formula rate structure or protocols shall be made as set forth in Section 9-201 of this Act, but nothing in this subsection (c) is intended to limit the Commission's authority under Article IX and other provisions of this Act to initiate an investigation of a participating utility's performance-based formula rate tariff, provided that any such changes shall be consistent with paragraphs (1) through (6) of this subsection (c). Any change ordered by the Commission shall be made at the same time new rates take effect following the Commission's next order pursuant to subsection (d) of this Section, provided that the new rates take effect no less than 30 days after the date on which the Commission issues an order adopting the change.
A participating utility that files a tariff pursuant to this subsection (c) must submit a one-time $200,000 filing fee at the time the Chief Clerk of the Commission accepts the filing, which shall be a recoverable expense.
In the event the performance-based formula rate is terminated, the then current rates shall remain in effect until such time as new rates are set pursuant to Article IX of this Act, subject to retroactive rate adjustment, with interest, to reconcile rates charged with actual costs. At such time that the performance-based formula rate is terminated, the participating utility's voluntary commitments and obligations under subsection (b) of this Section shall immediately terminate, except for the utility's obligation to pay an amount already owed to the fund for training grants pursuant to a Commission order issued under subsection (b) of this Section.
(d) Subsequent to the Commission's issuance of an order approving the utility's performance-based formula rate structure and protocols, and initial rates under subsection (c) of this Section, the utility shall file, on or before May 1 of each year, with the Chief Clerk of the Commission its updated cost inputs to the performance-based formula rate for the applicable rate year and the corresponding new charges. Each such filing shall conform to the following requirements and include the following information:
(1) The inputs to the performance-based formula rate
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| for the applicable rate year shall be based on final historical data reflected in the utility's most recently filed annual FERC Form 1 plus projected plant additions and correspondingly updated depreciation reserve and expense for the calendar year in which the inputs are filed. The filing shall also include a reconciliation of the revenue requirement that was in effect for the prior rate year (as set by the cost inputs for the prior rate year) with the actual revenue requirement for the prior rate year (determined using a year-end rate base) that uses amounts reflected in the applicable FERC Form 1 that reports the actual costs for the prior rate year. Any over-collection or under-collection indicated by such reconciliation shall be reflected as a credit against, or recovered as an additional charge to, respectively, with interest calculated at a rate equal to the utility's weighted average cost of capital approved by the Commission for the prior rate year, the charges for the applicable rate year. Provided, however, that the first such reconciliation shall be for the calendar year in which the utility files its performance-based formula rate tariff pursuant to subsection (c) of this Section and shall reconcile (i) the revenue requirement or requirements established by the rate order or orders in effect from time to time during such calendar year (weighted, as applicable) with (ii) the revenue requirement determined using a year-end rate base for that calendar year calculated pursuant to the performance-based formula rate using (A) actual costs for that year as reflected in the applicable FERC Form 1, and (B) for the first such reconciliation only, the cost of equity, which shall be calculated as the sum of 590 basis points plus the average for the applicable calendar year of the monthly average yields of 30-year U.S. Treasury bonds published by the Board of Governors of the Federal Reserve System in its weekly H.15 Statistical Release or successor publication. The first such reconciliation is not intended to provide for the recovery of costs previously excluded from rates based on a prior Commission order finding of imprudence or unreasonableness. Each reconciliation shall be certified by the participating utility in the same manner that FERC Form 1 is certified. The filing shall also include the charge or credit, if any, resulting from the calculation required by paragraph (6) of subsection (c) of this Section.
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Notwithstanding anything that may be to the contrary,
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| the intent of the reconciliation is to ultimately reconcile the revenue requirement reflected in rates for each calendar year, beginning with the calendar year in which the utility files its performance-based formula rate tariff pursuant to subsection (c) of this Section, with what the revenue requirement determined using a year-end rate base for the applicable calendar year would have been had the actual cost information for the applicable calendar year been available at the filing date.
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(2) The new charges shall take effect beginning on
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| the first billing day of the following January billing period and remain in effect through the last billing day of the next December billing period regardless of whether the Commission enters upon a hearing pursuant to this subsection (d).
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(3) The filing shall include relevant and necessary
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| data and documentation for the applicable rate year that is consistent with the Commission's rules applicable to a filing for a general increase in rates or any rules adopted by the Commission to implement this Section. Normalization adjustments shall not be required. Notwithstanding any other provision of this Section or Act or any rule or other requirement adopted by the Commission, a participating utility that is a combination utility with more than one rate zone shall not be required to file a separate set of such data and documentation for each rate zone and may combine such data and documentation into a single set of schedules.
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Within 45 days after the utility files its annual update of cost inputs to the performance-based formula rate, the Commission shall have the authority, either upon complaint or its own initiative, but with reasonable notice, to enter upon a hearing concerning the prudence and reasonableness of the costs incurred by the utility to be recovered during the applicable rate year that are reflected in the inputs to the performance-based formula rate derived from the utility's FERC Form 1. During the course of the hearing, each objection shall be stated with particularity and evidence provided in support thereof, after which the utility shall have the opportunity to rebut the evidence. Discovery shall be allowed consistent with the Commission's Rules of Practice, which Rules shall be enforced by the Commission or the assigned administrative law judge. The Commission shall apply the same evidentiary standards, including, but not limited to, those concerning the prudence and reasonableness of the costs incurred by the utility, in the hearing as it would apply in a hearing to review a filing for a general increase in rates under Article IX of this Act. The Commission shall not, however, have the authority in a proceeding under this subsection (d) to consider or order any changes to the structure or protocols of the performance-based formula rate approved pursuant to subsection (c) of this Section. In a proceeding under this subsection (d), the Commission shall enter its order no later than the earlier of 240 days after the utility's filing of its annual update of cost inputs to the performance-based formula rate or December 31. The Commission's determinations of the prudence and reasonableness of the costs incurred for the applicable calendar year shall be final upon entry of the Commission's order and shall not be subject to reopening, reexamination, or collateral attack in any other Commission proceeding, case, docket, order, rule or regulation, provided, however, that nothing in this subsection (d) shall prohibit a party from petitioning the Commission to rehear or appeal to the courts the order pursuant to the provisions of this Act.
In the event the Commission does not, either upon complaint or its own initiative, enter upon a hearing within 45 days after the utility files the annual update of cost inputs to its performance-based formula rate, then the costs incurred for the applicable calendar year shall be deemed prudent and reasonable, and the filed charges shall not be subject to reopening, reexamination, or collateral attack in any other proceeding, case, docket, order, rule, or regulation.
A participating utility's first filing of the updated cost inputs, and any Commission investigation of such inputs pursuant to this subsection (d) shall proceed notwithstanding the fact that the Commission's investigation under subsection (c) of this Section is still pending and notwithstanding any other law, order, rule, or Commission practice to the contrary.
(e) Nothing in subsections (c) or (d) of this Section shall prohibit the Commission from investigating, or a participating utility from filing, revenue-neutral tariff changes related to rate design of a performance-based formula rate that has been placed into effect for the utility. Following approval of a participating utility's performance-based formula rate tariff pursuant to subsection (c) of this Section, the utility shall make a filing with the Commission within one year after the effective date of the performance-based formula rate tariff that proposes changes to the tariff to incorporate the findings of any final rate design orders of the Commission applicable to the participating utility and entered subsequent to the Commission's approval of the tariff. The Commission shall, after notice and hearing, enter its order approving, or approving with modification, the proposed changes to the performance-based formula rate tariff within 240 days after the utility's filing. Following such approval, the utility shall make a filing with the Commission during each subsequent 3-year period that either proposes revenue-neutral tariff changes or re-files 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.
(f) Within 30 days after the filing of a tariff pursuant to subsection (c) of this Section, each participating utility shall develop and file with the Commission multi-year metrics designed to achieve, ratably (i.e., in equal segments) over a 10-year period, improvement over baseline performance values as follows:
(1) Twenty percent improvement in the System Average
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| Interruption Frequency Index, using a baseline of the average of the data from 2001 through 2010.
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(2) Fifteen percent improvement in the system
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| Customer Average Interruption Duration Index, using a baseline of the average of the data from 2001 through 2010.
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(3) For a participating utility other than a
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| combination utility, 20% improvement in the System Average Interruption Frequency Index for its Southern Region, using a baseline of the average of the data from 2001 through 2010. For purposes of this paragraph (3), Southern Region shall have the meaning set forth in the participating utility's most recent report filed pursuant to Section 16-125 of this Act.
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(3.5) For a participating utility other than a
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| combination utility, 20% improvement in the System Average Interruption Frequency Index for its Northeastern Region, using a baseline of the average of the data from 2001 through 2010. For purposes of this paragraph (3.5), Northeastern Region shall have the meaning set forth in the participating utility's most recent report filed pursuant to Section 16-125 of this Act.
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(4) Seventy-five percent improvement in the total
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| number of customers who exceed the service reliability targets as set forth in subparagraphs (A) through (C) of paragraph (4) of subsection (b) of 83 Ill. Adm. Code 411.140 as of May 1, 2011, using 2010 as the baseline year.
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(5) Reduction in issuance of estimated electric
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| bills: 90% improvement for a participating utility other than a combination utility, and 56% improvement for a participating utility that is a combination utility, using a baseline of the average number of estimated bills for the years 2008 through 2010.
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(6) Consumption on inactive meters: 90% improvement
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| for a participating utility other than a combination utility, and 56% improvement for a participating utility that is a combination utility, using a baseline of the average unbilled kilowatthours for the years 2009 and 2010.
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(7) Unaccounted for energy: 50% improvement for a
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| participating utility other than a combination utility using a baseline of the non-technical line loss unaccounted for energy kilowatthours for the year 2009.
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(8) Uncollectible expense: reduce uncollectible
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| expense by at least $30,000,000 for a participating utility other than a combination utility and by at least $3,500,000 for a participating utility that is a combination utility, using a baseline of the average uncollectible expense for the years 2008 through 2010.
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(9) Opportunities for minority-owned and female-owned
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| business enterprises: design a performance metric regarding the creation of opportunities for minority-owned and female-owned business enterprises consistent with State and federal law using a base performance value of the percentage of the participating utility's capital expenditures that were paid to minority-owned and female-owned business enterprises in 2010.
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The definitions set forth in 83 Ill. Adm. Code 411.20 as of May 1, 2011 shall be used for purposes of calculating performance under paragraphs (1) through (3.5) of this subsection (f), provided, however, that the participating utility may exclude up to 9 extreme weather event days from such calculation for each year, and provided further that the
participating utility shall exclude 9 extreme weather event days when calculating each year of the baseline period to the extent that there are 9 such days in a given year of the baseline period. For purposes of this Section, an extreme weather event day is a 24-hour calendar day (beginning at 12:00 a.m. and ending at 11:59 p.m.) during which any weather event (e.g., storm, tornado) caused interruptions for 10,000 or more of the participating utility's customers for 3 hours or more. If there are more than 9 extreme weather event days in a year, then the utility may choose no more than 9 extreme weather event days to exclude, provided that the same extreme weather event days are excluded from each of the calculations performed under paragraphs (1) through (3.5) of this subsection (f).
The metrics shall include incremental performance goals for each year of the 10-year period, which shall be designed to demonstrate that the utility is on track to achieve the performance goal in each category at the end of the 10-year period. The utility shall elect when the 10-year period shall commence for the metrics set forth in subparagraphs (1) through (4) and (9) of this subsection (f), provided that it begins no later than 14 months following the date on which the utility begins investing pursuant to subsection (b) of this Section, and when the 10-year period shall commence for the metrics set forth in subparagraphs (5) through (8) of this subsection (f), provided that it begins no later than 14 months following the date on which the Commission enters its order approving the utility's Advanced Metering Infrastructure Deployment Plan pursuant to subsection (c) of Section 16-108.6 of this Act.
The metrics and performance goals set forth in subparagraphs (5) through (8) of this subsection (f) are based on the assumptions that the participating utility may fully implement the technology described in subsection (b) of this Section, including utilizing the full functionality of such technology and that there is no requirement for personal on-site notification. If the utility is unable to meet the metrics and performance goals set forth in subparagraphs (5) through (8) of this subsection (f) for such reasons, and the Commission so finds after notice and hearing, then the utility shall be excused from compliance, but only to the limited extent achievement of the affected metrics and performance goals was hindered by the less than full implementation.
(f-5) The financial penalties applicable to the metrics described in subparagraphs (1) through (8) of subsection (f) of this Section, as applicable, shall be applied through an adjustment to the participating utility's return on equity of no more than a total of 30 basis points in each of the first 3 years, of no more than a total of 34 basis points
in each of the 3 years thereafter, and of no more than a total of 38 basis points in each
of the 4 years thereafter, as follows:
(1) With respect to each of the incremental annual
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| performance goals established pursuant to paragraph (1) of subsection (f) of this Section,
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(A) for each year that a participating utility
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| other than a combination utility does not achieve the annual goal, the participating utility's return on equity shall be reduced as follows: during years 1 through 3, by 5 basis points; during years 4 through 6, by 6 basis points; and during years 7 through 10, by 7 basis points; and
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(B) for each year that a participating utility
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| that is a combination utility does not achieve the annual goal, the participating utility's return on equity shall be reduced as follows: during years 1 through 3, by 10 basis points; during years 4 through 6, by 12 basis points; and during years 7 through 10, by 14 basis points.
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(2) With respect to each of the incremental annual
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| performance goals established pursuant to paragraph (2) of subsection (f) of this Section, for each year that the participating utility does not achieve each such goal, the participating utility's return on equity shall be reduced as follows: during years 1 through 3, by 5 basis points; during years 4 through 6, by 6 basis points; and during years 7 through 10, by 7 basis points.
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(3) With respect to each of the incremental annual
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| performance goals established pursuant to paragraphs (3) and (3.5) of subsection (f) of this Section, for each year that a participating utility other than a combination utility does not achieve both such goals, the participating utility's return on equity shall be reduced as follows: during years 1 through 3, by 5 basis points; during years 4 through 6, by 6 basis points; and during years 7 through 10, by 7 basis points.
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(4) With respect to each of the incremental annual
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| performance goals established pursuant to paragraph (4) of subsection (f) of this Section, for each year that the participating utility does not achieve each such goal, the participating utility's return on equity shall be reduced as follows: during years 1 through 3, by 5 basis points; during years 4 through 6, by 6 basis points; and during years 7 through 10, by 7 basis points.
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(5) With respect to each of the incremental annual
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| performance goals established pursuant to subparagraph (5) of subsection (f) of this Section, for each year that the participating utility does not achieve at least 95% of each such goal, the participating utility's return on equity shall be reduced by 5 basis points for each such unachieved goal.
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(6) With respect to each of the incremental annual
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| performance goals established pursuant to paragraphs (6), (7), and (8) of subsection (f) of this Section, as applicable, which together measure non-operational customer savings and benefits relating to the implementation of the Advanced Metering Infrastructure Deployment Plan, as defined in Section 16-108.6 of this Act, the performance under each such goal shall be calculated in terms of the percentage of the goal achieved. The percentage of goal achieved for each of the goals shall be aggregated, and an average percentage value calculated, for each year of the 10-year period. If the utility does not achieve an average percentage value in a given year of at least 95%, the participating utility's return on equity shall be reduced by 5 basis points.
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The financial penalties shall be applied as described in this subsection (f-5) for the 12-month period in which the deficiency occurred through a separate tariff mechanism, which shall be filed by the utility together with its metrics. In the event the formula rate tariff established pursuant to subsection (c) of this Section terminates, the utility's obligations under subsection (f) of this Section and this subsection (f-5) shall also terminate, provided, however, that the tariff mechanism established pursuant to subsection (f) of this Section and this subsection (f-5) shall remain in effect until any penalties due and owing at the time of such termination are applied.
The Commission shall, after notice and hearing, enter an order within 120 days after the metrics are filed approving, or approving with modification, a participating utility's tariff or mechanism to satisfy the metrics set forth in subsection (f) of this Section. On June 1 of each subsequent year, each participating utility shall file a report with the Commission that includes, among other things, a description of how the participating utility performed under each metric and an identification of any extraordinary events that adversely impacted the utility's performance. Whenever a participating utility does not satisfy the metrics required pursuant to subsection (f) of this Section, the Commission shall, after notice and hearing, enter an order approving financial penalties in accordance with this subsection (f-5). The Commission-approved financial penalties shall be applied beginning with the next rate year. Nothing in this Section shall authorize the Commission to reduce or otherwise obviate the imposition of financial penalties for failing to achieve one or more of the metrics established pursuant to subparagraphs (1) through (4) of subsection (f) of this Section.
(g) On or before July 31, 2014, each participating utility shall file a report with the Commission that sets forth the average annual increase in the average amount paid per kilowatthour for residential eligible retail customers, exclusive of the effects of energy efficiency programs, comparing the 12-month period ending May 31, 2012; the 12-month period ending May 31, 2013; and the 12-month period ending May 31, 2014. For a participating utility that is a combination utility with more than one rate zone, the weighted average aggregate increase shall be provided. The report shall be filed together with a statement from an independent auditor attesting to the accuracy of the report. The cost of the independent auditor shall be borne by the participating utility and shall not be a recoverable expense. "The average amount paid per kilowatthour" shall be based on the participating utility's tariffed rates actually in effect and shall not be calculated using any hypothetical rate or adjustments to actual charges (other than as specified for energy efficiency) as an input.
In the event that the average annual increase exceeds 2.5% as calculated pursuant to this subsection (g), then Sections 16-108.5, 16-108.6, 16-108.7, and 16-108.8 of this Act, other than this subsection, shall be inoperative as they relate to the utility and its service area as of the date of the report due to be submitted pursuant to this subsection and the utility shall no longer be eligible to annually update the performance-based formula rate tariff pursuant to subsection (d) of this Section. In such event, the then current rates shall remain in effect until such time as new rates are set pursuant to Article IX of this Act, subject to retroactive adjustment, with interest, to reconcile rates charged with actual costs, and the participating utility's voluntary commitments and obligations under subsection (b) of this Section shall immediately terminate, except for the utility's obligation to pay an amount already owed to the fund for training grants pursuant to a Commission order issued under subsection (b) of this Section.
In the event that the average annual increase is 2.5% or less as calculated pursuant to this subsection (g), then the performance-based formula rate shall remain in effect as set forth in this Section.
For purposes of this Section, the amount per kilowatthour means the total amount paid for electric service expressed on a per kilowatthour basis, and the total amount paid for electric service includes without limitation amounts paid for supply, transmission, distribution, surcharges, and add-on taxes exclusive of any increases in taxes or new taxes imposed after October 26, 2011 (the effective date of Public Act 97-616). For purposes of this Section, "eligible retail customers" shall have the meaning set forth in Section 16-111.5 of this Act.
The fact that this Section becomes inoperative as set forth in this subsection shall not be construed to mean that the Commission may reexamine or otherwise reopen prudence or reasonableness determinations already made.
(h) By December 31, 2017, the Commission shall prepare and file with the General Assembly a report on the infrastructure program and the performance-based formula rate. The report shall include the change in the average amount per kilowatthour paid by residential customers between June 1, 2011 and May 31, 2017. If the change in the total average rate paid exceeds 2.5% compounded annually, the Commission shall include in the report an analysis that shows the portion of the change due to the delivery services component and the portion of the change due to the supply component of the rate. The report shall include separate sections for each participating utility.
Sections 16-108.5, 16-108.6, 16-108.7, and 16-108.8 of this Act, other than this subsection (h) and subsection (i) of this Section, are inoperative after December 31, 2022 for every participating utility, after which time a participating utility shall no longer be eligible to annually update the performance-based formula rate tariff pursuant to subsection (d) of this Section. At such time, the then current rates shall remain in effect until such time as new rates are set pursuant to Article IX of this Act, subject to retroactive adjustment, with interest, to reconcile rates charged with actual costs.
The fact that this Section becomes inoperative as set forth in this subsection shall not be construed to mean that the Commission may reexamine or otherwise reopen prudence or reasonableness determinations already made.
(i) While a participating utility may use, develop, and maintain broadband systems and the delivery of broadband services, voice-over-internet-protocol services, telecommunications services, and cable and video programming services for use in providing delivery services and Smart Grid functionality or application to its retail customers, including, but not limited to, the installation, implementation and maintenance of Smart Grid electric system upgrades as defined in Section 16-108.6 of this Act, a participating utility is prohibited from providing to its retail customers broadband services, voice-over-internet-protocol services, telecommunications services, or cable or video programming services, unless they are part of a service directly related to delivery services or Smart Grid functionality or applications as defined in Section 16-108.6 of this Act, and from recovering the costs of such offerings from retail customers. The prohibition set forth in this subsection (i) is inoperative after December 31, 2027 for every participating utility.
(j) Nothing in this Section is intended to legislatively overturn the opinion issued in Commonwealth Edison Co. v. Ill. Commerce Comm'n, Nos. 2-08-0959, 2-08-1037, 2-08-1137, 1-08-3008, 1-08-3030, 1-08-3054, 1-08-3313 cons. (Ill. App. Ct. 2d Dist. Sept. 30, 2010). Public Act 97-616 shall not be construed as creating a contract between the General Assembly and the participating utility, and shall not establish a property right in the participating utility.
(k) The changes made in subsections (c) and (d) of this Section by Public Act 98-15 are intended to be a restatement and clarification of existing law, and intended to give binding effect to the provisions of House Resolution 1157 adopted by the House of Representatives of the 97th General Assembly and Senate Resolution 821 adopted by the Senate of the 97th General Assembly that are reflected in paragraph (3) of this subsection. In addition, Public Act 98-15 preempts and supersedes any final Commission orders entered in Docket Nos. 11-0721, 12-0001, 12-0293, and 12-0321 to the extent inconsistent with the amendatory language added to subsections (c) and (d).
(1) No earlier than 5 business days after May 22,
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| 2013 (the effective date of Public Act 98-15), each participating utility shall file any tariff changes necessary to implement the amendatory language set forth in subsections (c) and (d) of this Section by Public Act 98-15 and a revised revenue requirement under the participating utility's performance-based formula rate. The Commission shall enter a final order approving such tariff changes and revised revenue requirement within 21 days after the participating utility's filing.
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(2) Notwithstanding anything that may be to the
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| contrary, a participating utility may file a tariff to retroactively recover its previously unrecovered actual costs of delivery service that are no longer subject to recovery through a reconciliation adjustment under subsection (d) of this Section. This retroactive recovery shall include any derivative adjustments resulting from the changes to subsections (c) and (d) of this Section by Public Act 98-15. Such tariff shall allow the utility to assess, on current customer bills over a period of 12 monthly billing periods, a charge or credit related to those unrecovered costs with interest at the utility's weighted average cost of capital during the period in which those costs were unrecovered. A participating utility may file a tariff that implements a retroactive charge or credit as described in this paragraph for amounts not otherwise included in the tariff filing provided for in paragraph (1) of this subsection (k). The Commission shall enter a final order approving such tariff within 21 days after the participating utility's filing.
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(3) The tariff changes described in paragraphs (1)
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| and (2) of this subsection (k) shall relate only to, and be consistent with, the following provisions of Public Act 98-15: paragraph (2) of subsection (c) regarding year-end capital structure, subparagraph (D) of paragraph (4) of subsection (c) regarding pension assets, and subsection (d) regarding the reconciliation components related to year-end rate base and interest calculated at a rate equal to the utility's weighted average cost of capital.
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(4) Nothing in this subsection is intended to effect
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| a dismissal of or otherwise affect an appeal from any final Commission orders entered in Docket Nos. 11-0721, 12-0001, 12-0293, and 12-0321 other than to the extent of the amendatory language contained in subsections (c) and (d) of this Section of Public Act 98-15.
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(l) Each participating utility shall be deemed to have been in full compliance with all requirements of subsection (b) of this Section, subsection (c) of this Section, Section 16-108.6 of this Act, and all Commission orders entered pursuant to Sections 16-108.5 and 16-108.6 of this Act, up to and including May 22, 2013 (the effective date of Public Act 98-15). The Commission shall not undertake any investigation of such compliance and no penalty shall be assessed or adverse action taken against a participating utility for noncompliance with Commission orders associated with subsection (b) of this Section, subsection (c) of this Section, and Section 16-108.6 of this Act prior to such date. Each participating utility other than a combination utility shall be permitted, without penalty, a period of 12 months after such effective date to take actions required to ensure its infrastructure investment program is in compliance with subsection (b) of this Section and with Section 16-108.6 of this Act. Provided further, the following subparagraphs shall apply to a participating utility other than a combination utility:
(A) if the Commission has initiated a proceeding
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| pursuant to subsection (e) of Section 16-108.6 of this Act that is pending as of May 22, 2013 (the effective date of Public Act 98-15), then the order entered in such proceeding shall, after notice and hearing, accelerate the commencement of the meter deployment schedule approved in the final Commission order on rehearing entered in Docket No. 12-0298;
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(B) if the Commission has entered an order pursuant
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| to subsection (e) of Section 16-108.6 of this Act prior to May 22, 2013 (the effective date of Public Act 98-15) that does not accelerate the commencement of the meter deployment schedule approved in the final Commission order on rehearing entered in Docket No. 12-0298, then the utility shall file with the Commission, within 45 days after such effective date, a plan for accelerating the commencement of the utility's meter deployment schedule approved in the final Commission order on rehearing entered in Docket No. 12-0298; the Commission shall reopen the proceeding in which it entered its order pursuant to subsection (e) of Section 16-108.6 of this Act and shall, after notice and hearing, enter an amendatory order that approves or approves as modified such accelerated plan within 90 days after the utility's filing; or
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(C) if the Commission has not initiated a proceeding
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| pursuant to subsection (e) of Section 16-108.6 of this Act prior to May 22, 2013 (the effective date of Public Act 98-15), then the utility shall file with the Commission, within 45 days after such effective date, a plan for accelerating the commencement of the utility's meter deployment schedule approved in the final Commission order on rehearing entered in Docket No. 12-0298 and the Commission shall, after notice and hearing, approve or approve as modified such plan within 90 days after the utility's filing.
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Any schedule for meter deployment approved by the Commission pursuant to this subsection (l) shall take into consideration procurement times for meters and other equipment and operational issues. Nothing in Public Act 98-15 shall shorten or extend the end dates for the 5-year or 10-year periods set forth in subsection (b) of this Section or Section 16-108.6 of this Act. Nothing in this subsection is intended to address whether a participating utility has, or has not, satisfied any or all of the metrics and performance goals established pursuant to subsection (f) of this Section.
(m) The provisions of Public Act 98-15 are severable under Section 1.31 of the Statute on Statutes.
(Source: P.A. 102-1031, eff. 5-27-22; 103-154, eff. 6-30-23.)
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(220 ILCS 5/16-108.6) Sec. 16-108.6. Provisions relating to Smart Grid Advanced Metering Infrastructure Deployment Plan. (a) For purposes of this Section and Sections 16-108.7 and 16-108.8 of this Act: "Advanced Metering Infrastructure" or "AMI" means the communications hardware and software and associated system software that enables Smart Grid functions by creating a network between advanced meters and utility business systems and allowing collection and distribution of information to customers and other parties in addition to providing information to the utility itself. "Cost-beneficial" means a determination that the benefits of a participating utility's Smart Grid AMI Deployment Plan exceed the costs of the Smart Grid AMI Deployment Plan as initially filed with the Commission or as subsequently modified by the Commission. This standard is met if the present value of the total benefits of the Smart Grid AMI Deployment Plan exceeds the present value of the total costs of the Smart Grid AMI Deployment Plan. The total cost shall include all utility costs reasonably associated with the Smart Grid AMI Deployment Plan. The total benefits shall include the sum of avoided electricity costs, including avoided utility operational costs, avoided consumer power, capacity, and energy costs, and avoided societal costs associated with the production and consumption of electricity, as well as other societal benefits, including the greater integration of renewable and distributed power resources, reductions in the emissions of harmful pollutants and associated avoided health-related costs, other benefits associated with energy efficiency measures, demand-response activities, and the enabling of greater penetration of alternative fuel vehicles. "Participating utility" has the meaning set forth in Section 16-108.5 of this Act. "Smart Grid" means investments and policies that together promote one or more of the following goals: (1) Increased use of digital information and controls |
| technology to improve reliability, security, and efficiency of the electric grid.
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(2) Dynamic optimization of grid operations and
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| resources, with full cyber security.
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(3) Deployment and integration of distributed
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| resources and generation, including renewable resources.
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(4) Development and incorporation of demand-response,
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| demand-side resources, and energy efficiency resources.
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(5) Deployment of "smart" technologies (real-time,
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| automated, interactive technologies that optimize the physical operation of appliances and consumer devices) for metering, communications concerning grid operations and status, and distribution automation.
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(6) Integration of "smart" appliances and consumer
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(7) Deployment and integration of advanced
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| electricity storage and peak-shaving technologies, including plug-in electric and hybrid electric vehicles, thermal-storage air conditioning and renewable energy generation.
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(8) Provision to consumers of timely information and
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(9) Development of open access standards for
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| communication and interoperability of appliances and equipment connected to the electric grid, including the infrastructure serving the grid.
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(10) Identification and lowering of unreasonable or
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| unnecessary barriers to adoption of Smart Grid technologies, practices, services, and business models that support energy efficiency, demand-response, and distributed generation.
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"Smart Grid Advisory Council" means the group of stakeholders formed pursuant to subsection (b) of this Section for the purposes of advising and working with participating utilities on the development and implementation of a Smart Grid Advanced Metering Infrastructure Deployment Plan.
"Smart Grid electric system upgrades" means any of the following:
(1) metering devices, sensors, control devices, and
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| other devices integrated with and attached to an electric utility system that are capable of engaging in Smart Grid functions;
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(2) other monitoring and communications devices that
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| enable Smart Grid functions, including, but not limited to, distribution automation;
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(3) software that enables devices or computers to
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| engage in Smart Grid functions;
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(4) associated cyber secure data communication
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| network, including enhancements to cyber-security technologies and measures;
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(5) substation micro-processor relay upgrades;
(6) devices that allow electric or hybrid-electric
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| vehicles to engage in Smart Grid functions; or
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(7) devices that enable individual consumers to
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| incorporate distributed and micro-generation.
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"Smart Grid electric system upgrades" does not include expenditures for: (1) electricity generation, transmission, or distribution infrastructure or equipment that does not directly relate to or support installing, implementing or enabling Smart Grid functions; (2) physical interconnection of generators or other devices to the grid except those that are directly related to enabling Smart Grid functions; or (3) ongoing or routine operation, billing, customer relations, security, and maintenance.
"Smart Grid functions" means:
(1) the ability to develop, store, send, and receive
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| digital information concerning or enabling grid operations, electricity use, costs, prices, time of use, nature of use, storage, or other information relevant to device, grid, or utility operations, to or from or by means of the electric utility system through one or a combination of devices and technologies;
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(2) the ability to develop, store, send, and receive
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| digital information concerning electricity use, costs, prices, time of use, nature of use, storage, or other information relevant to device, grid, or utility operations to or from a computer or other control device;
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(3) the ability to measure or monitor electricity use
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| as a function of time of day, power quality characteristics such as voltage level, current, cycles per second, or source or type of generation and to store, synthesize, or report that information by digital means;
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(4) the ability to sense and localize disruptions or
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| changes in power flows on the grid and communicate such information instantaneously and automatically for purposes of enabling automatic protective responses to sustain reliability and security of grid operations;
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(5) the ability to detect, prevent, communicate with
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| regard to, respond to, or recover from system security threats, including cyber-security threats and terrorism, using digital information, media, and devices;
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(6) the ability of any device or machine to respond
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| to signals, measurements, or communications automatically or in a manner programmed by its owner or operator without independent human intervention;
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(7) the ability to use digital information to operate
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| functionalities on the electric utility grid that were previously electro-mechanical or manual;
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(8) the ability to use digital controls to manage and
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| modify electricity demand, enable congestion management, assist in voltage control, provide operating reserves, and provide frequency regulation; or
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(9) the ability to integrate electric plug-in
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| vehicles, distributed generation, and storage in a safe and cost-effective manner on the electric grid.
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(b) Within 30 days after the effective date of this amendatory Act of the 97th General Assembly, the Smart Grid Advisory Council shall be established, which shall consist of 9 total voting members with each member possessing either technical, business or consumer expertise in Smart Grid issues, 5 of whom shall be appointed by the Governor, one of whom shall be appointed by the Speaker of the House, one of whom shall be appointed by the Minority Leader of the House, one of whom shall be appointed by the President of the Senate, and one of whom shall be appointed by the Minority Leader of the Senate. Of the Governor's 5 appointments: (i) at least one must represent a non-profit membership organization whose mission is to cultivate innovation and technology-based economic development in Illinois by fostering public-private partnerships to develop and execute research and development projects, advocating for funding for research and development initiatives, and collaborating with public and private partners to attract and retain research and development resources and talent in Illinois; (ii) at least one must represent a non-profit public body corporate and politic created by law that has a duty to represent and protect residential utility consumers in Illinois; (iii) at least one must represent a membership organization that represents the interests of individuals and companies that own, operate, manage, and service commercial buildings in a municipality with a population of 1,000,000 or more inhabitants; and (iv) at least one must represent an alternative retail electric supplier that has obtained a certificate of service authority pursuant to Section 16-115 of this Act
and that is not an affiliate of a participating utility prior to one year after the effective date of this amendatory Act of the 97th General Assembly.
The Governor shall designate one of the members of the Council to serve as chairman, and that person shall serve as the chairman at the pleasure of the Governor. The members shall not be compensated for serving on the Smart Grid Advisory Council. The Smart Grid Advisory Council shall have the following duties:
(1) Serve as an advisor to participating utilities
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| subject to this Section and in the manner described in this Section, and the recommendations provided by the Council, although non-binding, shall be considered by the utilities.
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(2) Serve as trustees of the trust or foundation
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| established pursuant to Section 16-108.7 of this Act with the duties enumerated thereunder.
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(c) After consultation with the Smart Grid Advisory Council, each participating utility shall file a Smart Grid Advanced Metering Infrastructure Deployment Plan ("AMI Plan") with the Commission within 180 days after the effective date of this amendatory Act of the 97th General Assembly or by November 1, 2011, whichever is later, or in the case of a combination utility as defined in Section 16-108.5, by April 1, 2012, provided that a participating utility shall not file its plan until the evaluation report on the Pilot Program described in this subsection (c) is issued. The AMI Plan shall provide for investment over a 10-year period that is sufficient to implement the AMI Plan across its entire service territory in a manner that is consistent with subsection (b) of Section 16-108.5 of this Act. The AMI Plan shall contain:
(1) the participating utility's Smart Grid AMI vision
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| statement that is consistent with the goal of developing a cost-beneficial Smart Grid;
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(2) a statement of Smart Grid AMI strategy that
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| includes a description of how the utility evaluates and prioritizes technology choices to create customer value, including a plan to enhance and enable customers' ability to take advantage of Smart Grid functions beginning at the time an account has billed successfully on the AMI network;
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(3) a deployment schedule and plan that includes
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| deployment of AMI to all customers for a participating utility other than a combination utility, and to 62% of all customers for a participating utility that is a combination utility;
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(4) annual milestones and metrics for the purposes of
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| measuring the success of the AMI Plan in enabling Smart Grid functions; and enhancing consumer benefits from Smart Grid AMI; and
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(5) a plan for the consumer education to be
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| implemented by the participating utility.
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The AMI Plan shall be fully consistent with the standards of the National Institute of Standard and Technology (NIST) for Smart Grid interoperability that are in effect at the time the participating utility files its AMI Plan, shall include open standards and internet protocol to the maximum extent possible consistent with cyber security, and shall maximize, to the extent possible, a flexible smart meter platform that can accept remote device upgrades and contain sufficient internal memory capacity for additional storage capabilities, functions and services without the need for physical access to the meter.
The AMI Plan shall secure the privacy of personal information and establish the right of consumers to consent to the disclosure of personal energy information to third parties through electronic, web-based, and other means in accordance with State and federal law and regulations regarding consumer privacy and protection of consumer data.
After notice and hearing, the Commission shall, within 60 days of the filing of an AMI Plan, issue its order approving, or approving with modification, the AMI Plan if the Commission finds that the AMI Plan contains the information required in paragraphs (1) through (5) of this subsection (c) and further finds that the implementation of the AMI Plan will be cost-beneficial consistent with the principles established through the Illinois Smart Grid Collaborative, giving weight to the results of any Commission-approved pilot designed to examine the benefits and costs of AMI deployment. A participating utility's decision to invest pursuant to an AMI Plan approved by the Commission shall not be subject to prudence reviews in subsequent Commission proceedings. Nothing in this subsection (c) is intended to limit the Commission's ability to review the reasonableness of the costs incurred under the AMI Plan. A participating utility shall be allowed to recover the reasonable costs it incurs in implementing a Commission-approved AMI Plan, including the costs of retired meters, and may recover such costs through its tariffs, including the performance-based formula rate tariff approved pursuant to subsection (c) of Section 16-108.5 of this Act.
(d) The AMI Plan shall secure the privacy of the customer's personal information. "Personal information" for this purpose consists of the customer's name, address, telephone number, and other personally identifying information, as well as information about the customer's electric usage. Electric utilities, their contractors or agents, and any third party who comes into possession of such personal information by virtue of working on Smart Grid technology shall not disclose such personal information to be used in mailing lists or to be used for other commercial purposes not reasonably related to the conduct of the utility's business. Electric utilities shall comply with the consumer privacy requirements of the Personal Information Protection Act. In the event a participating utility receives revenues from the sale of information obtained through Smart Grid technology that is not personal information, the participating utility shall use such revenues to offset the revenue requirement.
(e) On April 1 of each year beginning in 2013 and after consultation with the Smart Grid Advisory Council, each participating utility shall submit a report regarding the progress it has made toward completing implementation of its AMI Plan. This report shall:
(1) describe the AMI investments made during the
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| prior 12 months and the AMI investments planned to be made in the following 12 months;
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(2) provide sufficient detail to determine the
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| utility's progress in meeting the metrics and milestones identified by the utility in its AMI Plan; and
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(3) identify any updates to the AMI Plan.
Within 21 days after the utility files its annual report, the Commission shall have authority, either upon complaint or its own initiative, but with reasonable notice, to enter upon an investigation regarding the utility's progress in implementing the AMI Plan as described in paragraph (1) of this subsection (e). If the Commission finds, after notice and hearing, that the participating utility's progress in implementing the AMI Plan is materially deficient for the given plan year, then the Commission shall issue an order requiring the participating utility to devise a corrective action plan, subject to Commission approval and oversight, to bring implementation back on schedule consistent with the AMI Plan. The Commission's order must be entered within 90 days after the utility files its annual report. If the Commission does not initiate an investigation within 21 days after the utility files its annual report, then the filing shall be deemed accepted by the Commission. The utility shall not be required to suspend implementation of its AMI Plan during any Commission investigation.
The participating utility's annual report regarding AMI Plan year 10 shall contain a statement verifying that the implementation of its AMI Plan is complete, provided, however, that if the utility is subject to a corrective action plan that extends the implementation period beyond 10 years, the utility shall include the verification statement in its final annual report. Following the date of a Commission order approving the final annual report or the date on which the final report is deemed accepted by the Commission, the utility's annual reporting obligations under this subsection (d) shall terminate, provided, however, that the utility shall have a continuing obligation to provide information, upon request, to the Commission and Smart Grid Advisory Council regarding the AMI Plan.
(f) Each participating utility shall pay a pro rata share, based on number of customers, of $5,000,000 per year to the trust or foundation established pursuant to Section 16-108.7 of this Act for each plan year of the AMI Plan, which shall be used for purposes of providing customer education regarding smart meters and related consumer-facing technologies and services and 70% of which shall be a recoverable expense; provided that other reasonable amounts expended by the utility for such consumer education shall not be subject to the 70% limitation of this subsection.
(g) Within 60 days after the Commission approves a participating utility's AMI Plan pursuant to subsection (c) of this Section, the participating utility, after consultation with the Smart Grid Advisory Council, shall file a proposed tariff with the Commission that offers an opt-in market-based peak time rebate program to all residential retail customers with smart meters that is designed to provide, in a competitively neutral manner, rebates to those residential retail customers that curtail their use of electricity during specific periods that are identified as peak usage periods. The total amount of rebates shall be the amount of compensation the utility obtains through markets or programs at the applicable regional transmission organization. The utility shall make all reasonable attempts to secure funding for the peak time rebate program through markets or programs at the applicable regional transmission organization. The rules and procedures for consumers to opt-in to the peak time rebate program shall include electronic sign-up, be designed to maximize participation, and be included on the utility's website. The Commission shall monitor the performance of programs established pursuant to this subsection (g) 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 of at least 4 years, resulting in net benefits to the residential customers of the participating utility.
(h) If Section 16-108.5 of this Act becomes inoperative with respect to one or more participating utilities as set forth in subsection (g) or (h) of that Section, then Sections 16-108.5, 16-108.6, 16-108.7, and 16-108.8 of this Act shall become inoperative as to each affected utility and its service area on the same date as Section 16-108.5 becomes inoperative.
(Source: P.A. 97-616, eff. 10-26-11; 97-646, eff. 12-30-11.)
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(220 ILCS 5/16-108.15) Sec. 16-108.15. Rate impacts. (a) Each electric utility that serves more than 500,000 retail customers in the State shall file with the Commission the reports required by this Section, which shall identify the actual and projected average monthly increases in residential retail customers' electric bills due to future energy investment costs for the applicable period or periods. (b) The average monthly increase calculation shall be comprised of the following components: (1) Beginning with the 2017 calendar year, the |
| average monthly amount paid by residential retail customers, expressed on a cents-per-kilowatthour basis, to recover future energy investment costs, which include the charges to recover the costs incurred by the utility under the following provisions:
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(A) Sections 8-103, Section 8-103B, and 16-111.5B
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| of this Act, as applicable, and as such costs may be recovered under Sections 8-103, 8-103B, 16-111.5B or Section 16-108.5 of this Act;
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(B) subsection (d-5) of Section 1-75 of the
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| Illinois Power Agency Act, as such costs may be recovered under subsection (k) of Section 16-108 of this Act; and
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(C) Section 16-107.6 of this Act.
Beginning with the 2018 calendar year, each of the
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| average monthly charges calculated in subparagraphs (A) through (C) of this paragraph (1) shall be equal to the average of each such charge applied over a period that commences with the calendar year ending December 31, 2017 and ends with the most recently completed calendar year prior to the calculation or calculations required by this Section.
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(2) The sum of the following:
(A) net energy savings to residential retail
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| customers that are attributable to the implementation of voltage optimization measures under Section 8-103B of this Act, expressed on a cents-per-kilowatthour basis, which are estimated energy and capacity benefits for residential retail customers minus the measure costs recovered from those customers, divided by the total number of residential retail customers, which quotient shall be divided by the months in the relevant period; notwithstanding this subparagraph (A), a utility may elect not to include an estimate of net energy savings as described in this subparagraph (A), in which case the value under this subparagraph (A) shall be zero; and
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(B) for an electric utility that serves more than
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| 3,000,000 retail customers in the State, the benefits of the programs described in Section 16-108.10 of this Act, which are $0.00030 per kilowatthour for the 2017, 2018, 2019, 2020, and 2021 calendar years.
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Beginning with the 2018 calendar year, each of
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| the values identified in subparagraphs (A) and (B) of this paragraph (2) shall be equal to the average of each such value during a period that commences with the calendar year ending December 31, 2017 and ends with the most recently completed calendar year prior to the calculation or calculations required by this Section.
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(3) For an electric utility that serves more than
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| 3,000,000 retail customers in the State, the residential retail customer energy efficiency charges shall be $2.33 per month for the 2017 calendar year, provided that such charge shall be increased by 4% per year thereafter; for an electric utility that serves more than 500,000 but less than 3,000,000 retail customers in the State, the residential retail customer energy efficiency charges shall be $3.94 per month for the 2017 calendar year, provided that such charge shall be increased by 4% per year thereafter. Beginning with the 2018 calendar year, this charge shall be equal to the average of the charges applied over a period that commences with the calendar year ending December 31, 2017 and ends with the most recently completed calendar year prior to the calculation or calculations required by this Section.
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(c)(1) No later than June 30, 2017, an electric
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| utility subject to this Section shall submit a report to the Commission that sets forth the utility's rolling 10-year projection of the values of each of the components described in paragraphs (1) through (3) of subsection (b) of this Section. No later than February 15, 2018 and every February 15 thereafter until February 15, 2031, each utility shall submit a report to the Commission that identifies the value of the actual charges applied during the immediately preceding calendar year and updates its rolling 10-year projection based on such actual charges provided that, beginning with the February 15, 2021 report and for each report thereafter, the period of time covered by such projection shall not extend beyond December 31, 2030. Each report submitted under this subsection (c) shall calculate the actual average monthly increase in residential retail customers' electric bills due to future energy investment costs during the immediately preceding calendar year and shall also calculate the projected average monthly increase in residential retail customers' electric bills due to such costs over the rolling 10-year period. Such calculations shall be performed by subtracting the sum of paragraph (2) of subsection (b) of this Section from the sum of paragraph (1) of such subsection (b), multiplying such difference by, as applicable, the actual or forecasted average monthly kilowatthour consumption for the residential retail customer class for the applicable period, and subtracting from such product the applicable value identified under paragraph (3) of such subsection (b).
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If the actual or projected average monthly increase
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| for residential retail customers of electric utility that serves more than 3 million retail customers in the State exceeds $0.25, or the actual or projected average monthly increase for residential retail customers of an electric utility that serves more than 500,000 but less than 3 million retail customers in the State exceeds $0.35, then the applicable utility shall comply with the provisions of paragraphs (2) through (4) of this subsection (c), as applicable.
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(2) If the projected average monthly increase for
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| residential retail customers during a calendar year exceeds the applicable limitation set forth in paragraph (1) of this subsection (c), then the utility shall comply with the following provisions, as applicable:
|
|
(A) If an exceedance is projected during the
|
| first four calendar year of the rolling 10-year projection, then the utility shall include in its report submitted under paragraph (1) of this subsection (c) the utility's proposal or proposals to decrease the future energy investment costs described in paragraph (1) of subsection (b) of this Section to ensure that the limitation set forth in such paragraph (1) is not exceeded. The Commission shall, after notice and hearing, enter an order directing the utility to implement one or more proposals, as such proposals may be modified by the Commission. The Commission shall have the authority under this subparagraph (A) to approve modifications to the contracts executed under subsection (d-5) of Section 1-75 of the Illinois Power Agency Act. If the Commission approves modifications to such contracts, then the supplier shall have the option of accepting the modifications or terminating the modified contract or contracts, subject to the termination requirements and notice provisions set forth in item (i) of subparagraph (B) of paragraph (4) of this Section.
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|
(B) If an exceedance is projected during any
|
| calendar year during the last 6 years of the 10-year projection, then the utility shall demonstrate in its report submitted under paragraph (1) of this subsection (c) how the utility will reduce the future energy investment costs described in paragraph (1) of subsection (b) of this Section to ensure that the limitation set forth in such paragraph (1) is not exceeded.
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|
(3) If the actual average monthly increase for
|
| residential retail customers during a calendar year exceeded the limitation set forth in paragraph (1) of this subsection (c), then the utility shall prepare and file with the Commission, at the time it submits its report under paragraph (1) of this subsection (c), a corrective action plan that identifies how the utility will immediately reduce expenditures so that the utility will be in compliance with such limitation beginning on January 1 of the next calendar year. The Commission shall initiate an investigation to determine the factors that contributed to the actual average monthly increase exceeding such limitation for the applicable calendar year, and shall, after notice and hearing, enter an order approving, or approving with modification, the utility's corrective action plan within 120 days after the utility files such plan. The Commission shall also submit a report to the General Assembly no later than 30 days after it enters such order, and the report shall explain the results of the Commission's investigation and findings and conclusions of its order.
|
|
(4) If the actual average monthly increase for
|
| residential retail customers during a calendar year exceeds the limitation set forth in paragraph (1) of this subsection (c) for two consecutive years, then the utility shall indicate in its report filed under paragraph (1) of this subsection (c) whether the utility will proceed with or terminate the future energy investments described and authorized under subsection (d-5) of the Illinois Power Agency Act and Sections 8-103B and 16-107.6 of this Act. The utility shall be subject to the requirements of subparagraph (A) or (B) of this paragraph (4), as applicable.
|
|
(A) If the utility indicates that it will proceed
|
| with the future energy investments, then it shall be subject to the corrective action plan requirements set forth in paragraph (3) of this subsection (c). In addition, the utility must commit to apply a credit to residential retail customers' bills if the actual average monthly increase for such customers exceeds the limitation set forth in paragraph (1) of this subsection (c) for the year in which the utility files its corrective action plan, which credit shall be in an amount that equals the portion by which the increase exceeds such limitation. The Commission shall initiate an investigation to determine the factors that contributed to the actual average monthly increase exceeding such limitation for the applicable calendar year, including an analysis of the factors contributing to the limitation being exceeded for two consecutive years, and shall, after notice and hearing, enter an order approving, or approving with modification, the utility's corrective action plan within 120 days after the utility files such plan. The Commission shall also submit a supplemental report to the General Assembly no later than 30 days after it enters such order, and the report shall explain the results of the Commission's investigation and findings and conclusions of its order.
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|
(B) If the utility indicates that it will
|
| terminate future energy investments, then the Commission shall, notwithstanding anything to the contrary:
|
|
(i) Order the utility to terminate the
|
| contract or contracts executed under subsection (d-5) of Section 1-75 of the Illinois Power Agency Act, pursuant to the contract termination provisions set forth in such subsection (d-5), provided that notice of such termination must be made at least 3 years and 75 days prior to the effective date of such termination. In the event that only a portion of the contracts executed under such subsection (d-5) are terminated for a particular zero emission facility, then the zero emission facility may elect to terminate all of the contracts executed for that facility under such subsection (d-5).
|
|
(ii) Within 30 days after the utility submits
|
| its report indicates that it will terminate future energy investments, initiate a proceeding to approve the process for terminating future expenditures under Section 16-107.6 of the Public Utilities Act. The Commission shall, after notice and hearing, enter its order approving such process no later than 120 days after initiating such proceeding.
|
|
(iii) Within 30 days after the utility
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| submits its report indicates that it will terminate future energy investments, initiate a proceeding under Section 8-103B of this Act to reduce the cumulative persisting annual savings goals previously approved by the Commission under such Section to ensure just and reasonable rates. The Commission shall, after notice and hearing, enter its order approving such goal reductions no later than 120 days after initiating such proceeding.
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|
Notwithstanding the termination of future energy
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| investments pursuant to this subparagraph (B), the utility shall be permitted to continue to recover the costs of such investments that were incurred prior to such termination, including but not limited to all costs that are recovered through regulatory assets created under Sections 8-103B and 16-107.6 of this Act. Nothing in this Section shall limit the utility's ability to fully recover such costs. The utility shall also be permitted to continue to recover the costs of all payments made under contracts executed under subsection (d-5) until the effective date of the contract's termination.
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|
(Source: P.A. 99-906, eff. 6-1-17 .)
|
(220 ILCS 5/16-108.16) Sec. 16-108.16. Commercial Rate Impacts. (a) Each electric utility that serves more than 500,000 retail customers in the State shall file with the Commission the reports required by this Section, which shall identify the annual average increases due to future energy investment costs for the applicable period or periods in electric bills to commercial and industrial retail customers. For purposes of this Section, "commercial and industrial retail customers" means non-residential retail customers other than those customers who are exempt from subsections (a) through (j) of Section 8-103B of this Act under subsection (l) of Section 8-103B. (b) The increase determination required by subsection (a) of this Section shall be based on a calculation comprised of the following components: (1) Beginning with the 2017 calendar year, the |
| average annual amount paid by commercial and industrial retail customers, expressed on a cents-per-kilowatthour basis, to recover future energy investment costs, which include the charges to recover the costs incurred by the utility under the following provisions:
|
|
(A) Sections 8-103, Section 8-103B, and 16-111.5B
|
| of this Act, as applicable, and as such costs may be recovered under Sections 8-103, 8-103B, 16-111.5B or Section 16-108.5 of this Act;
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|
(B) subsection (d-5) of Section 1-75 of the
|
| Illinois Power Agency Act, as such costs may be recovered under subsection (k) of Section 16-108 of this Act; and
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|
(C) Section 16-107.6 of this Act.
Beginning with the 2018 calendar year, each of the
|
| average annual charges calculated in subparagraphs (A) through (C) of this paragraph (1) shall be equal to the average of each such charge applied over a period that commences with the calendar year ending December 31, 2017 and ends with the most recently completed calendar year prior to the calculation or calculations required by this Section.
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|
(2) The sum of the following:
(A) annual net energy savings to commercial and
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| industrial retail customers that are attributable to the implementation of voltage optimization measures under Section 8-103B of this Act, expressed on a cents-per-kilowatthour basis, which are estimated energy and capacity benefits for commercial and industrial retail customers minus the measure costs recovered from those customers, divided by the average annual kilowatt-hour consumption of commercial and industrial retail customers; notwithstanding this subparagraph (A), a utility may elect not to include an estimate of net energy savings as described in this subparagraph (A), in which case the value under this subparagraph (A) shall be zero;
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|
(B) the average annual cents-per-kilowatthour
|
| charge applied under Section 8-103 of this Act to commercial and industrial retail customers during calendar year 2016 to recover the costs authorized by such Section; and
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|
(C) incremental energy efficiency savings, which
|
| shall be calculated by subtracting the value determined in item (ii) of this subparagraph (C) from the value determined in item (i) of this subparagraph and dividing the difference by the value identified in item (iii) of this subparagraph:
|
|
(i) Total value, in dollars, of the
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| cumulative persisting annual saving achieved from the installation or implementation of all energy efficiency measures for commercial and industrial retail customers under Sections 8-103, 8-103B and 16-111.5 of this Act, net of the cumulative annual percentage savings in kilowatt-hours, if any, calculated under subparagraph (A) of this paragraph (2).
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|
(ii) 2016 value, which shall equal the value
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| calculated under item (i) of this subparagraph (C) multiplied by the quotient of (aa) the cumulative persisting annual savings, in kilowatt-hours, achieved from the installation or implementation of all energy efficiency measures for commercial and industrial retail customers under Sections 8-103, 8-103B and 16-111.5B of this Act as of December 31, 2016, divided by (bb) the cumulative persisting annual savings, in kilowatt-hours, from the installation or implementation of all energy efficiency measures for commercial and industrial retail customers under Sections 8-103, 8-103B and 16-111.5 of this Act, net of the cumulative annual percentage savings in kilowatt-hours, if any, calculated under subparagraph (A) of this paragraph (2).
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|
(iii) The average annual kilowatt-hour
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| consumption of those commercial and industrial retail customers that installed or implemented energy efficiency measures under energy efficiency programs or plans approved pursuant to Sections 8-103, 8-103B or 16-111.5B of this Act.
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|
Beginning with the 2018 calendar year, each of
|
| the values identified in subparagraphs (A) and (C) of this paragraph (2) shall be equal to the average of each such value during a period that commences with the calendar year ending December 31, 2017 and ends with the most recently completed calendar year prior to the calculation or calculations required by this Section.
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|
For purposes of this Section, cumulative
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| persisting annual savings shall have the meaning set forth in Section 8-103B of this Act, and energy efficiency measures shall have the meaning set forth in Section 1-10 of the Illinois Power Agency Act.
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|
(c)(1) No later than June 30, 2017, and every June 30
|
| thereafter until June 30, 2027, an electric utility subject to this Section shall submit a report to the Commission that sets forth the utility's 10-year projection of the values of each of the components described in paragraphs (1) and (2) of subsection (b) of this Section. Each utility's report to the Commission shall identify the result of the computation performed under this Section for the immediately preceding calendar year and update its 10-year projection. Such calculations shall be performed by subtracting the sum of paragraph (2) of subsection (b) of this Section from the sum of paragraph (1) of such subsection (b).
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|
In the event that the actual or projected average
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| annual increase for commercial and industrial retail customers exceeds 1.3% of 8.90 cents-per-kilowatthour, which is the average amount paid per kilowatt-hour for electric service during the year ending December 31, 2015 by Illinois commercial retail customers, as reported to the Edison Electric Institute, then the applicable utility shall comply with the provisions of paragraphs (2) through (4) of this subsection (c), as applicable.
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|
(2) In the event that the projected average annual
|
| increase for commercial and industrial retail customers during a calendar year exceeds the applicable limitation set forth in paragraph (1) of this subsection (c), then the utility shall comply with the following provisions, as applicable:
|
|
(A) If an exceedance is projected during the
|
| first four calendar years of the 10-year projection, then the utility shall include in its report submitted under paragraph (1) of this subsection (c) the utility's proposal or proposals to decrease the future energy investment costs described in paragraph (1) of subsection (b) of this Section to ensure that the limitation set forth in such paragraph (1) is not exceeded. The Commission shall, after notice and hearing, enter an order directing the utility to implement one or more proposals, as such proposals may be modified by the Commission. The Commission shall have the authority under this subparagraph (A) to approve modifications to the contracts executed under subsection (d-5) of Section 1-75 of the Illinois Power Agency Act. If the Commission approves modifications to such contracts that are in an amount that reduces the quantities to be procured under such contracts by more than 7%, then the supplier shall have the option of accepting the modifications or terminating the modified contract or contracts, subject to the termination requirements and notice provisions set forth in item (i) of subparagraph (B) of paragraph (4) of this Section.
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|
(B) If an exceedance is projected during any
|
| calendar year during the last 6 years of the 10-year projection, then the utility shall demonstrate in its report submitted under paragraph (1) of this subsection (c) how the utility will reduce the future energy investment costs described in paragraph (1) of subsection (b) of this Section to ensure that the limitation set forth in such paragraph (1) is not exceeded.
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|
(3) If the actual average annual increase for
|
| commercial and industrial retail customers during a calendar year exceeded the limitation set forth in paragraph (1) of this subsection (c), then the utility shall prepare and file with the Commission, at the time it submits its report under paragraph (1) of this subsection (c), a corrective action plan. The Commission shall initiate an investigation to determine the factors that contributed to the actual average annual increase exceeding such limitation for the applicable calendar year, and shall, after notice and hearing, enter an order approving, or approving with modification, the utility's corrective action plan within 120 days after the utility files such plan. The Commission shall also submit a report to the General Assembly no later than 30 days after it enters such order, and the report shall explain the results of the Commission's investigation and findings and conclusions of its order.
|
|
(4) If the actual average annual increase for
|
| commercial and industrial retail customers during a calendar year exceeds the limitation set forth in paragraph (1) of this subsection (c) for two consecutive years, then the utility shall indicate in its report filed under paragraph (1) of this subsection (c) whether the utility will proceed with or terminate the future energy investments described and authorized under subsection (d-5) of the Illinois Power Agency Act and Sections 8-103B and 16-107.6 of this Act. The utility's election shall be subject to the requirements of subparagraph (A) or (B) of this paragraph (4), as applicable.
|
|
(A) If the utility elects to proceed with the
|
| future energy investments, then it shall be subject to the corrective action plan requirements set forth in paragraph (3) of this subsection (c). In addition, the utility must commit to apply a credit to commercial and industrial retail customers' bills if the actual average annual increase for such customers exceeds the limitation set forth in paragraph (1) of this subsection (c) for the year in which the utility files its corrective action plan, which credit shall be in an amount that equals the portion by which the increase exceeds such limitation. The Commission shall initiate an investigation to determine the factors that contributed to the actual average annual increase exceeding such limitation for the applicable calendar year, including an analysis of the factors contributing to the limitation being exceeded for two consecutive years, and shall, after notice and hearing, enter an order approving, or approving with modification, the utility's corrective action plan within 120 days after the utility files such plan. The Commission shall also submit a supplemental report to the General Assembly no later than 30 days after it enters such order, and the report shall explain the results of the Commission's investigation and findings and conclusions of its order.
|
|
(B) If the utility elects to terminate future
|
| energy investments, then the Commission shall, notwithstanding anything to the contrary:
|
|
(i) Order the utility to terminate the
|
| contract or contracts executed under subsection (d-5) of Section 1-75 of the Illinois Power Agency Act, pursuant to the contract termination provisions set forth in such subsection (d-5), provided that notice of such termination must be made at least 3 years and 75 days prior to the effective date of such termination. In the event that only a portion of the contracts executed under such subsection (d-5) are terminated for a particular zero emission facility, then the zero emission facility may elect to terminate all of the contracts executed for that facility under such subsection (d-5).
|
|
(ii) Within 30 days of the utility's report
|
| identifying its election to terminate future energy investments, initiate a proceeding to approve the process for terminating future expenditures under Sections 16-107.6 of the Public Utilities Act. The Commission shall, after notice and hearing, enter its order approving such process no later than 120 days after initiating such proceeding.
|
|
(iii) Within 30 days of the utility's report
|
| identifying its election to terminate future energy investments, initiate a proceeding under Section 8-103B of this Act to reduce the cumulative persisting annual savings goals previously approved by the Commission under such Section to ensure just and reasonable rates. The Commission shall, after notice and hearing, enter its order approving such goal reductions no later than 120 days after initiating such proceeding.
|
|
Notwithstanding the termination of future energy
|
| investments pursuant to this subparagraph (B), the utility shall be permitted to continue to recover the costs of such investments that were incurred prior to such termination, including but not limited to all costs that are recovered through regulatory assets created under Sections 8-103B and 16-107.6 of this Act. Nothing in this Section shall limit the utility's ability to fully recover such costs. The utility shall also be permitted to continue to recover the costs of all payments made under contracts executed under subsection (d-5) until the effective date of the contract's termination.
|
|
(5) Notwithstanding anything to the contrary, if,
|
| under this Section or subsection (m) of Section 16-108 of this Act, modifications to the contracts executed under subsection (d-5) of Section 1-75 of the Illinois Power Agency Act are, in total, in an amount that reduces the quantities to procured under such contracts by more than 10%, then the supplier shall have the option of accepting the modifications or terminating the modified contract or contracts, subject to the termination requirements and notice provisions set forth in item (i) of subparagraph (B) of paragraph (4) of this Section.
|
|
(Source: P.A. 99-906, eff. 6-1-17 .)
|
(220 ILCS 5/16-108.18) Sec. 16-108.18. Performance-based ratemaking. (a) The General Assembly finds: (1) That improving the alignment of utility customer |
| and company interests is critical to ensuring equity, rapid growth of distributed energy resources, electric vehicles, and other new technologies that substantially change the makeup of the grid and protect Illinois residents and businesses from potential economic and environmental harm from the State's energy systems.
|
|
(2) There is urgency around addressing increasing
|
| threats from climate change and assisting communities that have borne disproportionate impacts from climate change, including air pollution, greenhouse gas emissions, and energy burdens. Addressing this problem requires changes to the business model under which utilities in Illinois have traditionally functioned.
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|
(3) Providing targeted incentives to support change
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| through a new performance-based structure to enhance ratemaking is intended to enable alignment of utility, customer, community, and environmental goals.
|
|
(4) Though Illinois has taken some measures to move
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| utilities to performance-based ratemaking through the establishment of performance incentives and a performance-based formula rate under the Energy Infrastructure Modernization Act, these measures have not been sufficiently transformative in urgently moving electric utilities toward the State's ambitious energy policy goals: protecting a healthy environment and climate, improving public health, and creating quality jobs and economic opportunities, including wealth building, especially in economically disadvantaged communities and communities of color.
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|
(5) These measures were not developed through a
|
| process to understand first what performance measures and penalties would help drive the sought-after behavior by the utilities.
|
|
(6) While the General Assembly has not made a finding
|
| that the spending related to the Energy Infrastructure and Modernization Act and its performance metrics was not reasonable, it is important to address concerns that these measures may have resulted in excess utility spending and guaranteed profits without meaningful improvements in customer experience, rate affordability, or equity.
|
|
(7) Discussions of performance incentive mechanisms
|
| must always take into account the affordability of customer rates and bills for all customers, including low-income customers.
|
|
(8) The General Assembly therefore directs the
|
| Illinois Commerce Commission to complete a transition that includes a comprehensive performance-based regulation framework for electric utilities serving more than 500,000 customers. The breadth of this framework should revise existing utility regulations to position Illinois electric utilities to effectively and efficiently achieve current and anticipated future energy needs of this State, while ensuring affordability for consumers.
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|
(b) As used in this Section:
"Commission" means the Illinois Commerce Commission.
"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.
"Economically disadvantaged communities" means areas of one or more census tracts where average household income does not exceed 80% of area median income.
"Environmental justice communities" means the definition of that term as used and as may be updated in the long-term renewable resources procurement plan by the Illinois Power Agency and its Program Administrator in the Illinois Solar for All Program.
"Equity investment eligible community" means the geographic areas throughout Illinois which would most benefit from equitable investments by the State designed to combat discrimination. Specifically, the equity investment eligible communities shall be defined as the following areas:
(1) R3 Areas as established pursuant to Section
|
| 10-40 of the Cannabis Regulation and Tax Act, where residents have historically been excluded from economic opportunities, including opportunities in the energy sector; and
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|
(2) Environmental justice communities, as defined by
|
| the Illinois Power Agency pursuant to the Illinois Power Agency Act, where residents have historically been subject to disproportionate burdens of pollution, including pollution from the energy sector.
|
|
"Performance incentive mechanism" means an instrument by which utility performance is incentivized, which could include a monetary performance incentive.
"Performance metric" means a manner of measurement for a particular utility activity.
(c) Through coordinated, comprehensive system planning, ratemaking, and performance incentives, the performance-based ratemaking framework should be designed to accomplish the following objectives:
(1) maintain and improve service reliability and
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| safety, including and particularly in environmental justice, low-income and equity investment eligible communities;
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|
(2) decarbonize utility systems at a pace that meets
|
| or exceeds State climate goals, while also ensuring the affordability of rates for all customers, including low-income customers;
|
|
(3) direct electric utilities to make cost-effective
|
| investments that support achievement of Illinois' clean energy policies, including, at a minimum, investments designed to integrate distributed energy resources, comply with critical infrastructure protection standards, plans, and industry best practices, and support and take advantage of potential benefits from the electric vehicle charging and other electrification, while mitigating the impacts;
|
|
(4) choose cost-effective assets and services,
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| whether utility-supplied or through third-party contracting, considering both economic and environmental costs and the effects on utility rates, to deliver high-quality service to customers at least cost;
|
|
(5) maintain the affordability of electric delivery
|
| services for all customers, including low-income customers;
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|
(6) maintain and grow a diverse workforce, diverse
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| supplier procurement base and, for relevant programs, diverse approved-vendor pools, including increased opportunities for minority-owned, female-owned, veteran-owned, and disability-owned business enterprises;
|
|
(7) improve customer service performance and
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|
(8) address the particular burdens faced by
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| consumers in environmental justice and equity investment eligible communities, including shareholder, consumer, and publicly funded bill payment assistance and credit and collection policies, and ensure equitable disconnections, late fees, or arrearages as a result of utility credit and collection practices, which may include consideration of impact by zip code; and
|
|
(9) implement or otherwise enhance current
|
| supplier diversity programs to increase diverse contractor participation in professional services, subcontracting, and prime contracting opportunities with programs that address barriers to access. Supplier diversity programs shall address specific barriers related to RFP and contract access, access to capital, information technology and cyber security access and costs, administrative burdens, and quality control with specific metrics, outcomes, and demographic data reported.
|
|
(d) Multi-Year Rate Plan.
(1) If an electric utility had a performance-based
|
| formula rate in effect under Section 16-108.5 as of December 31, 2020, then the utility may file a petition proposing tariffs implementing a 4-year Multi-Year Rate Plan as provided in this Section no later than, January 20, 2023, for delivery service rates to be effective for the billing periods January 1, 2024 through December 31, 2027. The Commission shall issue an order approving or approving as modified the utility's plan no later than December 20, 2023. The term "Multi-Year Rate Plan" refers to a plan establishing the base rates the utility shall charge for each delivery year of the 4-year period to be covered by the plan, which shall be subject to modification only as expressly allowed in this Section.
|
|
(2) A utility proposing a Multi-Year Rate Plan shall
|
| provide a 4-year investment plan and a description of the utility's major planned investments, including, at a minimum, all investments of $2,000,000 or greater over the plan period for an electric utility that serves more than 3,000,000 retail customers in the State or $500,000 for an electric utility that serves less than 3,000,000 retail customers in the State but more than 500,000 retail customers in the State. The 4-year investment plan must be consistent with the Multi-Year Integrated Grid Plan described in Section 16-105.17 of this Act. The investment plan shall provide sufficiently detailed information, as required by the Commission, including, at a minimum, a description of each investment, the location of the investment, and an explanation of the need for and benefit of such an investment to the extent known.
|
|
(3) The Multi-Year Rate Plan shall be implemented
|
| through a tariff filed with the Commission consistent with the provisions of this paragraph (3) that shall apply to all delivery service customers. The Commission shall initiate and conduct an investigation of the tariff in a manner consistent with the provisions of this paragraph (3) and the provisions of Article IX of this Act, to the extent they do not conflict with this paragraph (3). The Multi-Year Rate Plan approved by the Commission shall do the following:
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|
(A) Provide for the recovery of the utility's
|
| forecasted rate base, based on the 4-year investment plan and the utility's Integrated Grid Plan. The forecasted rate base must include the utility's planned capital investments, with rates based on average annual plant investment, and investment-related costs, including income tax impacts, depreciation, and ratemaking adjustments and costs that are prudently incurred and reasonable in amount consistent with Commission practice and law. The process used to develop the forecasts must be iterative, rigorous, and lead to forecasts that reasonably represent the utility's investments during the forecasted period and ensure that the investments are projected to be used and useful during the annual investment period and least cost, consistent with the provisions of Articles VIII and IX of this Act.
|
|
(B) The cost of equity shall be approved by the
|
| Commission consistent with Commission practice and law.
|
|
(C) The revenue requirement shall reflect the
|
| utility's actual capital structure for the applicable calendar year. A year-end capital structure that includes a common equity ratio of up to and including 50% of the total capital structure shall be deemed prudent and reasonable. A higher common equity ratio must be specifically approved by the Commission.
|
|
(E) Provide for recovery of prudent and
|
| reasonable projected operating expenses, giving effect to ratemaking adjustments, consistent with Commission practice and law under Article IX of this Act. Operating expenses for years after the first year of the Multi-Year Rate Plan may be estimated by the use of known and measurable changes, expense reductions associated with planned capital investments as appropriate, and reasonable and appropriate escalators, indices, or other metrics.
|
|
(F) Amortize the amount of unprotected
|
| property-related excess accumulated deferred income taxes in rates as of January 1, 2023 over a period ending December 31, 2027, unless otherwise required to amortize the excess deferred income tax pursuant to Section 16-108.21 of this Act.
|
|
(G) Allow recovery of incentive compensation
|
| expense that is based on the achievement of operational metrics, including metrics related to budget controls, outage duration and frequency, safety, customer service, efficiency and productivity, environmental compliance and attainment of affordability and environmental goals, and other goals and metrics approved by the Commission. Incentive compensation expense that is based on net income or an affiliate's earnings per share shall not be recoverable.
|
|
(H) To the maximum extent practicable, align the
|
| 4-year investment plan and annual capital budgets with the electric utility's Multi-Year Integrated Grid Plan.
|
|
(4) The Commission shall establish annual rates for
|
| each year of the Multi-Year Rate Plan that accurately reflect and are based only upon the utility's reasonable and prudent costs of service over the term of the plan, including the effect of all ratemaking adjustments consistent with Commission practice and law as determined by the Commission, provided that the costs are not being recovered elsewhere in rates. Tariff riders authorized by the Commission may continue outside of a plan authorized under this Section to the extent such costs are not recovered elsewhere in rates. For the first multi-year rate plan, the burden of proof shall be on the electric utility to establish the prudence of investments and expenditures and to establish that such investments consistent with and reasonably necessary to meet the requirements of the utility's first approved Multi-Year Integrated Grid Plan described in Section 16-105.17 of this Act. For subsequent Multi-Year Rate Plans, the burden of proof shall be on the electric utility to establish the prudence of investments and expenditures and to establish that such investments are consistent with and reasonably necessary to meet the requirements of the utility's most recently approved Multi-Year Integrated Grid Plan described in Section 16-105.17 of this Act. The sole fact that a cost differs from that incurred in a prior period or that an investment is different from that described in the Multi-Year Integrated Grid Plan shall not imply the imprudence or unreasonableness of that cost or investment. The sole fact that an investment is the same or similar to that described in the Multi-Year Integrated Grid Plan shall not imply prudence and reasonableness of that investment.
|
|
(5) To facilitate public transparency, all materials,
|
| data, testimony, and schedules shall be provided to the Commission in an editable, machine-readable electronic format including .doc, .docx, .xls, .xlsx, and similar file formats, but not including .pdf or .exif. Should utilities designate any materials confidential, they shall have an affirmative duty to explain why the particular information is marked confidential. In determining prudence and reasonableness of rates, the Commission shall make its determination based upon the record, including each public comment filed or provided orally at open meetings consistent with the Commission's rules and practices.
|
|
(6) The Commission may, by order, establish terms,
|
| conditions, and procedures for submitting and approving a Multi-Year Rate Plan necessary to implement this Section and ensure that rates remain just and reasonable during the course of the plan, including terms and procedures for rate adjustment.
|
|
(7) An electric utility that files a tariff pursuant
|
| to paragraph (3) of this subsection (e) must submit a one-time $300,000 filing fee at the time the Chief Clerk of the Commission accepts the filing, which shall be a recoverable expense.
|
|
(8) An electric utility operating under a Multi-Year
|
| Rate Plan shall file a new Multi-Year Rate Plan at least 300 days prior to the end of the initial Multi-Year Rate Plan unless it elects to file a general rate case pursuant to paragraph (9), and every 4 years thereafter, with a rate-effective date of the proposed tariffs such that, after the Commission suspension period, the rates would take effect immediately at the close of the final year of the initial Multi-Year Rate Plan. In subsequent Multi-Year Rate Plans, as in the initial plans, utilities and stakeholders may propose additional metrics that achieve the outcomes described in paragraph (2) of subsection (f) of this Section.
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|
(9) Election of Rate Case.
(A) On or before the date prescribed by
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| subparagraph (B) of paragraph (9) of this Section, electric utilities that serve more than 500,000 retail customers in the State shall file either a general rate case under Section 9-201 of this Act, or a Multi-Year Rate Plan, as set forth in paragraph (1) of this subsection (d).
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(B) Electric utilities described in
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| subparagraph (A) of paragraph (9) of this Section shall file their initial general rate case or Multi-Year Rate Plan, as applicable, with the Commission no later than January 20, 2023.
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(C) Notwithstanding which rate filing option
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| an electric utility elects to file on the date prescribed by subparagraph (B) of paragraph (9) of this Section, the electric utility shall be subject to the Multi-year Integrated Plan filing requirements.
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(D) Following its initial rate filing pursuant
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| to paragraph (2), an electric utility subject to the requirements of this Section shall thereafter be permitted to elect a different rate filing option consistent with any filing intervals established for a general rate case or Multi-Year Rate Plan, as follows:
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(i) An electric utility that initially
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| elected to file a Multi-Year Rate Plan and thereafter elects to transition to a general rate case may do so upon completion of the 4-year Multi-Year Rate Plan by filing a general rate case at the same time that the utility would have filed its subsequent Multi-Year Rate Plan, as specified in paragraph (8) of this subsection (d). Notwithstanding this election, the annual adjustment of the final year of the Multi-Year Rate Plan shall proceed as specified in paragraph (6) of subsection (f).
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(ii) An electric utility that initially
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| elected to a file general rate case and thereafter elects to transition to a Multi-Year Rate Plan may do so only at the 4-year filing intervals identified by paragraph (8) of this subsection (d).
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(10) The Commission shall approve tariffs
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| establishing rate design for all delivery service customers unless the electric utility makes the election specified in Section 16-105.5, in which case the rate design shall be subject to the provisions of that Section.
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(11) The Commission shall establish requirements for
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| annual performance evaluation reports to be submitted annually for performance metrics. Such reports shall include, but not be limited to, a description of the utility's performance under each metric and an identification of any extraordinary events that adversely affected the utility's performance.
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(12) For the first Multi-Year Rate Plan, the
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| Commission shall consolidate its investigation with the proceeding under Section 16-105.17 to establish the Multi-Year Integrated Grid Plan no later than 45 days after plan filing.
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(13) Where a rate change under a Multi-Year Rate Plan
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| will result in a rate increase, an electric utility may propose a rate phase-in plan that the Commission shall approve with or without modification or deny in its final order approving the new delivery services rates. A proposed rate phase-in plan under this paragraph (13) must allow the new delivery services rates to be implemented in no more than 2 steps, as follows: in the first step, at least 50% of the approved rate increase must be reflected in rates, and, in the second step, 100% of the rate increase must be reflected in rates. The second step's rates must take effect no later than 12 months after the first step's rates were placed into effect. The portion of the approved rate increase not implemented in the first step shall be recorded on the electric utility's books as a regulatory asset, and shall accrue carrying costs to ensure that the utility does not recover more or less than it otherwise would because of the deferral. This portion shall be recovered, with such carrying costs at the weighted average cost of capital, through a surcharge applied to retail customer bills that (i) begins no later than 12 months after the date on which the second step's rates went into effect and (ii) is applied over a period not to exceed 24 months. Nothing in this paragraph is intended to limit the Commission's authority to mitigate the impact of rates caused by rate plans, or any other instance on a revenue-neutral basis; nor shall it mitigate a utility's ability to make proposals to mitigate the impact of rates. When a deferral, or similar method, is used to mitigate the impact of rates, the utility should be allowed to recover carrying costs.
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(14) Notwithstanding the provisions of Section (13),
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| the Commission may, on its own initiative, take revenue-neutral measures to relieve the impact of rate increases on customers. Such initiatives may be taken by the Commission in the first Multi-Year Rate Plan, subsequent multi-year plans, or in other instances described in this Act.
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(15) Whenever during the pendency of a Multi-year
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| Rate Plan, an electric utility subject to this Section becomes aware that, due to circumstances beyond its control, prudent operating practices will require the utility to make adjustments to the Multi-Year Rate Plan, the electric utility may file a petition with the Commission requesting modification of the approved annual revenue requirements included in the Multi-Year Rate Plan. The electric utility must support its request with evidence demonstrating why a modification is necessary, due to circumstances beyond the utility's control, to follow prudent operating practices and must set forth the changes to each annual revenue requirement to be approved, and the basis for any changes in anticipated operating expenses or capital investment levels. The utility shall affirmatively address the impact of the changes on the Multi-Year Integrated Grid Plan and Multi-Year Rate Plan originally submitted and approved by the Commission. Any interested party may file an objection to the changes proposed, or offer alternatives to the utility's proposal, as supported by testimony and evidence. After notice and hearing, the Commission shall issue a final order regarding the electric utility's request no later than 180 days after the filing of the petition.
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(e) Performance incentive mechanisms.
(1) The electric industry is undergoing rapid
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| transformation, including fundamental changes in how electricity is generated, procured, and delivered and how customers are choosing to participate in the supply and delivery of electricity to and from the electric grid. Building upon the State's goals to increase the procurement of electricity from renewable energy resources, including distributed generation and storage devices, the General Assembly finds that electric utilities should make cost-effective investments that support moving forward on Illinois' clean energy policies. It is therefore in the State's interest for the Commission to establish performance incentive mechanisms in order to better tie utility revenues to performance and customer benefits, accelerate progress on Illinois energy and other goals, ensure equity and affordability of rates for all customers, including low-income customers, and hold utilities publicly accountable.
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|
(2) The Commission shall approve, based on the
|
| substantial evidence proffered in the proceeding initiated pursuant to this subsection performance metrics that, to the extent practicable and achievable by the electric utility, encourage cost-effective, equitable utility achievement of the outcomes described in this subsection (e) while ensuring no degradation in the significant performance improvement achieved through previously established performance metrics. For each electric utility, the Commission shall approve metrics designed to achieve incremental improvements over baseline performance values and targets, over a performance period of up to 10 years, and no less than 4 years.
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|
(A) The Commission shall approve no more than
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| 8 metrics, with at least one metric from each of the categories below, for each electric utility, from subparagraphs (i) through (vi) of this subsection (A). Upon a utility request, the Commission may approve the use of a specific, measurable, and achievable tracking metric described in paragraph (3) of subsection (e) as a performance metric pursuant to paragraph (2) of subsection (e).
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|
(i) Metrics designed to ensure the
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| utility maintains and improves the high standards of both overall and locational reliability and resiliency, and makes improvements in power quality, including and particularly in environmental justice and equity investment eligible communities.
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(ii) Peak load reductions attributable to
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| demand response programs.
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|
(iii) Supplier diversity expansion, including
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| diverse contractor participation in professional services, subcontracting, and prime contracting opportunities, development of programs that address the barriers to access, aligning demographics of contractors to the demographics in the utility's service territory, establish long-term mentoring relationships that develop and remove barriers to access for diverse and underserved contractors. The utilities shall provide solutions, resources, and tools to address complex barriers of entry related to costly and time-intensive cyber security requirements, increasingly complex information technology requirements, insurance barriers, service provider sign-up process barriers, administrative process barriers, and other barriers that inhibit access to RFPs and contracts. For programs with contracts over $1,000,000, winning bidders must demonstrate a subcontractor development or mentoring relationship with at least one of their diverse subcontracting partners for a core component of the scope of the project. The mentoring time and cost shall be taken into account in the creation of RFP and shall include a structured and measured plan by the prime contractor to increase the capabilities of the subcontractor in their proposed scope. The metric shall include reporting on all supplier diversity programs by goals, program results, demographics and geography, with separate reporting by category of minority-owned, female-owned, veteran-owned, and disability-owned business enterprise metrics. The report shall include resources and expenses committed to the programs and conversion rates of new diverse utility contractors.
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|
(iv) Achieve affordable customer delivery
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| service costs, with particular emphasis on keeping the bills of lower-income households, households in equity investment eligible communities, and household in environmental justice communities within a manageable portion of their income and adopting credit and collection policies that reduce disconnections for these households specifically and for customers overall to ensure equitable disconnections, late fees, or arrearages as a result of utility credit and collection practices, which may include consideration of impact by zip code.
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|
(v) Metrics designed around the utility's
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| timeliness to customer requests for interconnection in key milestone areas, such as: initial response, supplemental review, and system feasibility study; improved average service reliability index for those customers that have interconnected a distributed renewable energy generation device to the utility's distribution system and are lawfully taking service under an applicable tariff; offering a variety of affordable rate options, including demand response, time of use rates for delivery and supply, real-time pricing rates for supply; comprehensive and predictable net metering, and maximizing the benefits of grid modernization and clean energy for ratepayers; and improving customer access to utility system information according to consumer demand and interest.
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|
(vi) Metrics designed to measure the
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| utility's customer service performance, which may include the average length of time to answer a customer's call by a customer service representative, the abandoned call rate and the relative ranking of the electric utility, by a reputable third-party organization, in customer service satisfaction when compared to other similar electric utilities in the Midwest region.
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|
(B) Performance metrics shall include a
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| description of the metric, a calculation method, a data collection method, annual performance targets, and any incentives or penalties for the utility's achievement of, or failure to achieve, their performance targets, provided that the total amount of potential incentives and penalties shall be symmetrical. Incentives shall be rewards or penalties or both, reflected as basis points added to, or subtracted from, the utility's cost of equity. The metrics and incentives shall apply for the entire time period covered by a Multi-Year Rate Plan. The total for all metrics shall be equal to 40 basis points, however, the Commission may adjust the basis points upward or downward by up to 20 basis points for any given Multi-Year Rate Plan, as appropriate, but in no event may the total exceed 60 basis points or fall below 20 basis points.
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|
(C) Metrics related to reliability shall be
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| implemented to ensure equitable benefits to environmental justice and equity investment eligible communities, as defined in this Act.
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|
(D) The Commission shall approve performance
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| metrics that are reasonably within control of the utility to achieve. The Commission also shall not approve a metric that is solely expected to have the effect of reducing the workforce. Performance metrics should measure outcomes and actual, rather than projected, results where possible. Nothing in this paragraph is intended to require that different electric utilities must be subject to the same metrics, goals, or incentives.
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|
(E) Increases or enhancements to an existing
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| performance goal or target shall be considered in light of other metrics, cost-effectiveness, and other factors the Commission deems appropriate. Performance metrics shall include one year of tracking data collected in a consistent manner, verifiable by an independent evaluator in order to establish a baseline and measure outcomes and actual results against projections where possible.
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|
(F) For the purpose of determining reasonable
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| performance metrics and related incentives, the Commission shall develop a methodology to calculate net benefits that includes customer and societal costs and benefits and quantifies the effect on delivery rates. In determining the appropriate level of a performance incentive, the Commission shall consider: the extent to which the amount is likely to encourage the utility to achieve the performance target in the least cost manner; the value of benefits to customers, the grid, public health and safety, and the environment from achievement of the performance target, including in particular benefits to equity investment eligible community; the affordability of customer's electric bills, including low-income customers, the utility's revenue requirement, the promotion of renewable and distributed energy, and other such factors that the Commission deems appropriate. The consideration of these factors shall result in an incentive level that ensures benefits exceed costs for customers.
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|
(G) Achievement of performance metrics are
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| based on the assumptions that the utility will adopt or implement the technology and equipment, and make the investments to the extent reasonably necessary to achieve the goal. If the electric utility is unable to meet the performance metrics as a result of extraordinary circumstances outside of its control, including but not limited to government-declared emergencies, then the utility shall be permitted to file a petition with the Commission requesting that the utility be excused from compliance with the applicable performance goal or goals and the associated financial incentives and penalties. The burden of proof shall be on the utility, consistent with Article IX, and the utility's petition shall be supported by substantial evidence. The Commission shall, after notice and hearing, enter its order approving or denying, in whole or in part, the utility's petition based on the extent to which the utility demonstrated that its achievement of the affected metrics and performance goals was hindered by extraordinary circumstances outside of the utility's control.
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|
(3) The Commission shall approve reasonable and
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| appropriate tracking metrics to collect and monitor data for the purpose of measuring and reporting utility performance and for establishing future performance metrics. These additional tracking metrics shall include at least one metric from each of the following categories of performance:
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|
(A) Minimize emissions of greenhouse gases and
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| other air pollutants that harm human health, particularly in environmental justice and equity investment eligible communities, through minimizing total emissions by accelerating electrification of transportation, buildings and industries where such electrification results in net reductions, across all fuels and over the life of electrification measures, of greenhouse gases and other pollutants, taking into consideration the fuel mix used to produce electricity at the relevant hour and the effect of accelerating electrification on electricity delivery services rates, supply prices and peak demand, provided the revenues the utility receives from accelerating electrification of transportation, buildings and industries exceed the costs.
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|
(B) Enhance the grid's flexibility to adapt to
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| increased deployment of nondispatchable resources, improve the ability and performance of the grid on load balancing, and offer a variety of rate plans to match consumer consumption patterns and lower consumer bills for electricity delivery and supply.
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|
(C) Ensure rates reflect cost savings
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| attributable to grid modernization and utilize distributed energy resources that allow the utility to defer or forgo traditional grid investments that would otherwise be required to provide safe and reliable service.
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|
(D) Metrics designed to create and sustain
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| full-time-equivalent jobs and opportunities for all segments of the population and workforce, including minority-owned businesses, women-owned businesses, veteran-owned businesses, and businesses owned by a person or persons with a disability, and that do not, consistent with State and federal law, discriminate based on race or socioeconomic status as a result of this amendatory Act of the 102nd General Assembly.
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|
(E) Maximize and prioritize the allocation of
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| grid planning benefits to environmental justice and economically disadvantaged customers and communities, such that all metrics provide equitable benefits across the utility's service territory and maintain and improve utility customers' access to uninterrupted utility services.
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|
(4) The Commission may establish new tracking and
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| performance metrics in future Multi-Year Rate Plans to further measure achievement of the outcomes set forth in paragraph (2) of subsection (f) of this Section and the other goals and requirements of this Section.
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|
(5) The Commission shall also evaluate metrics
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| that were established in prior Multi-Year Rate Plans to determine if there has been an unanticipated material change in circumstances such that adjustments are required to improve the likelihood of the outcomes described in paragraph (2) of subsection (f). For metrics that were established in prior Multi-Year Rate Plan proceedings and that the Commission elects to continue, the design of these metrics, including the goals of tracking metrics and the targets and incentive levels and structures of performance metrics, may be adjusted pursuant to the requirements in this Section. The Commission may also change, adjust or phase out tracking and performance metrics that were established in prior Multi-Year Rate Plan proceedings if these metrics no longer meet the requirements of this Section or if they are rendered obsolete by the changing needs and technology of an evolving grid. Additionally, performance metrics that no longer require an incentive to create improved utility performance may become tracking metrics in a Multi-Year Rate Plan proceeding.
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|
(6) The Commission shall initiate a workshop
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| process no later than August 1, 2021, or 15 days after the effective date of this amendatory Act of the 102nd General Assembly, whichever is later, for the purpose of facilitating the development of metrics for each utility. The workshop shall be coordinated by the staff of the Commission, or a facilitator retained by staff, and shall be organized and facilitated in a manner that encourages representation from diverse stakeholders and ensures equitable opportunities for participation, without requiring formal intervention or representation by an attorney. Working with staff of the Commission the facilitator may conduct a combination of workshops specific to a utility or applicable to multiple utilities where content and stakeholders are substantially similar. The workshop process shall conclude no later than October 31, 2021. Following the workshop, the staff of the Commission, or the facilitator retained by the Staff, shall prepare and submit a report to the Commission that identifies the participants in the process, the metrics proposed during the process, any material issues that remained unresolved at the conclusions of such process, and any recommendations for workshop process improvements. Any workshop participant may file comments and reply comments in response to the Staff report.
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|
(A) No later than January, 20, 2022, each
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| electric utility that intends to file a petition pursuant to subsection (b) of this Section shall file a petition with the Commission seeking approval of its performance metrics, which shall include for each metric, at a minimum, (i) a detailed description, (ii) the calculation of the baseline, (iii) the performance period and overall performance goal, provided that the performance period shall not commence prior to January 1, 2024, (iv) each annual performance goal, (v) the performance adjustment, which shall be a symmetrical basis point increase or decrease to the utility's cost of equity based on the extent to which the utility achieved the annual performance goal, and (vi) the new or modified tariff mechanism that will apply the performance adjustments. The Commission shall issue its order approving, or approving with modification, the utility's proposed performance metrics no later than September 30, 2022.
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|
(B) No later than August 1, 2025, the Commission
|
| shall initiate a workshop process that conforms to the workshop purpose and requirements of this paragraph (6) of this Section to the extent they do not conflict. The workshop process shall conclude no later than October 31, 2025, and the staff of the Commission, or the facilitator retained by the Staff, shall prepare and submit a report consistent with the requirements described in this paragraph (6) of this Section. No later than January 20, 2026, each electric utility subject to the requirements of this Section shall file a petition the reflects, and is consistent with, the components required in this paragraph (6) of this Section, and the Commission shall issue its order approving, or approving with modification, the utility's proposed performance metrics no later than September 30, 2026.
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|
(f) On May 1 of each year, following the approval of the first Multi-Year Rate Plan and its initial year, the Commission shall open an annual performance evaluation proceeding to evaluate the utilities' performance on their metric targets during the year just completed, as well as the appropriate Annual Adjustment as defined in paragraph (6). The Commission shall determine the performance and annual adjustments to be applied through a surcharge in the following calendar year.
(1) On February 15 of each year, prior to the
|
| annual performance evaluation proceeding, each utility shall file a performance evaluation report with the Commission that includes a description of and all data supporting how the utility performed under each performance metric and an identification of any extraordinary events that adversely impacted the utility's performance.
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|
(2) The metrics approved under this Section are
|
| based on the assumptions that the utility may fully implement the technology and equipment, and make the investments, required to achieve the metrics and performance goals. If the utility is unable to meet the metrics and performance goals because it was hindered by unanticipated technology or equipment implementation delays, government-declared emergencies, or other investment impediments, then the utility shall be permitted to file a petition with the Commission on or before the date that its report is due pursuant to paragraph (1) of this subsection (f) requesting that the utility be excused from compliance with the applicable performance goal or goals. The burden of proof shall be on the utility, consistent with Article IX, and the utility's petition shall be supported by substantial evidence. No later than 90 days after the utility files its petition, the Commission shall, after notice and hearing, enter its order approving or denying, in whole or in part, the utility's petition based on the extent to which the utility demonstrated that its achievement of the affected metrics and performance goals was hindered by unanticipated technology or equipment implementation delays, or other investment impediments, that were reasonably outside of the utility's control.
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|
(3) The electric utility shall provide for an
|
| annual independent evaluation of its performance on metrics. The independent evaluator shall review the utility's assumptions, baselines, targets, calculation methodologies, and other relevant information, especially ensuring that the utility's data for establishing baselines matches actual performance, and shall provide a report to the Commission in each annual performance evaluation describing the results. The independent evaluator shall present this report as evidence as a nonparty participant and shall not be represented by the utility's legal counsel. The independent evaluator shall be hired through a competitive bidding process with approval of the contract by the Commission.
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|
The Commission shall consider the report of the
|
| independent evaluator in determining the utility's achievement of performance targets. Discrepancies between the utility's assumptions, baselines, targets, or calculations and those of the independent evaluator shall be closely scrutinized by the Commission. If the Commission finds that the utility's reported data for any metric or metrics significantly and incorrectly deviates from the data reported by the independent evaluator, then the Commission shall order the utility to revise its data collection and calculation process within 60 days, with specifications where appropriate.
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|
(4) The Commission shall, after notice and hearing
|
| in the annual performance evaluation proceeding, enter an order approving the utility's performance adjustment based on its achievement of or failure to achieve its performance targets no later than December 20 each year. The Commission-approved penalties or incentives shall be applied beginning with the next calendar year.
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|
(5) In order to promote the transparency of utility
|
| investments during the effective period of a multi-year rate plan, inform the Commission's investigation and adjustment of rates in the annual adjustment process, and to facilitate the participation of stakeholders in the annual adjustment process, an electric utility with an effective Multi-Year Rate Plan shall, within 90 days of the close of each quarter during the Multi-Year Rate Plan period, submit to the Commission a report that summarizes the additions to utility plant that were placed into service during the prior quarter, which for purposes of the report shall be the most recently closed fiscal quarter. The report shall also summarize the utility plant the electric utility projects it will place into service through the end of the calendar year in which the report is filed. The projections, estimates, plans, and forward-looking information that are provided in the reports pursuant to this paragraph (5) are for planning purposes and are intended to be illustrative of the investments that the utility proposes to make as of the time of submittal. Nothing in this paragraph (5) precludes, or is intended to limit, a utility's ability to modify and update its projections, estimates, plans, and forward-looking information previously submitted in order to reflect stakeholder input or other new or updated information and analysis, including, but not limited to, changes in specific investment needs, customer electric use patterns, customer applications and preferences, and commercially available equipment and technologies, however the utility shall explain any changes or deviations between the projected investments from the quarterly reports and actual investments in the annual report. The reports submitted pursuant to this subsection are intended to be flexible planning tools, and are expected to evolve as new information becomes available. Within 7 days of receiving a quarterly report, the Commission shall timely make such report available to the public by posting it on the Commission's website. Each quarterly report shall include the following detail:
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|
(A) The total dollar value of the additions to
|
| utility plant placed in service during the prior quarter;
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|
(B) A list of the major investment categories the
|
| electric utility used to manage its routine standing operational activities during the prior quarter including the total dollar amount for the work reflected in each investment category in which utility plant in service is equal to or greater than $2,000,000 for an electric utility that serves more than 3,000,000 customers in the State or $500,000 for an electric utility that serves less than 3,000,000 customers but more than 500,000 customers in the State as of the last day of the quarterly reporting period, as well as a summary description of each investment category;
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|
(C) A list of the projects which the electric
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| utility has identified by a unique investment tracking number for utility plant placed in service during the prior quarter for utility plant placed in service with a total dollar value as of the last day of the quarterly reporting period that is equal to or greater than $2,000,000 for an electric utility that serves more than 3,000,000 customers in the State or $500,000 for an electric utility that serves less than 3,000,000 retail customers but more than $500,000 retail customers in the State, as well as a summary of each project;
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|
(D) The estimated total dollar value of the
|
| additions to utility plant projected to be placed in service through the end of the calendar year in which the report is filed;
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|
(E) A list of the major investment categories
|
| the electric utility used to manage its routine standing operational activities with utility plant projected to be placed in service through the end of the calendar year in which the report is filed, including the total dollar amount for the work reflected in each investment category in which utility plant in service is projected to be equal to or greater than $2,000,000 for an electric utility that serves more than 3,000,000 customers in the State or $500,000 for an electric utility that serves less than 3,000,000 retail customers but more than 500,000 retail customers in the State, as well as a summary description of each investment category; and
|
|
(F) A list of the projects for which the
|
| electric utility has identified by a unique investment tracking number for utility plant projected to be placed in service through the end of the calendar year in which the report is filed with an estimated dollar value that is equal to or greater than $2,000,000 for an electric utility that serves more than 3,000,000 customers in the State or $500,000 for an electric utility that serves less than 3,000,000 retails customers but more than $500,000 retail customers in the State, as well as a summary description of each project.
|
|
(6) As part of the Annual Performance Adjustment,
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| the electric utility shall submit evidence sufficient to support a determination of its actual revenue requirement for the applicable calendar year, consistent with the provisions of paragraphs (d) and (f) of this subsection. The electric utility shall bear the burden of demonstrating that its costs were prudent and reasonable, subject to the provisions of paragraph (4) of this subsection (f). The Commission's review of the electric utility's annual adjustment shall be based on the same evidentiary standards, including, but not limited to, those concerning the prudence and reasonableness of the known and measurable costs forecasted to be incurred by the utility, and the used and usefulness of the actual plant investment pursuant to Section 9-211 of this Act, that the Commission applies in a proceeding to review a filing for changes in rates pursuant to Section 9-201 of this Act. The Commission shall determine the prudence and reasonableness of the actual costs incurred by the utility during the applicable calendar year, as well as determine the original cost of plant in service as of the end of the applicable calendar year. The Commission shall then determine the Annual Adjustment, which shall mean the amount by which, the electric utility's actual revenue requirement for the applicable year of the Multi-Year Rate Plan either exceeded, or was exceeded by, the revenue requirement approved by the Commission for such calendar year, plus carrying costs calculated at the weighted average cost of capital approved for the Multi-Year Rate Plan.
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|
The Commission's determination of the electric
|
| utility's actual revenue requirement for the applicable calendar year shall be based on:
|
|
(A) the Commission-approved used and useful,
|
| prudent and reasonable actual costs for the applicable calendar year, which shall be determined pursuant to the following criteria:
|
|
(i) The overall level of actual costs
|
| incurred during the calendar year, provided that the Commission may not allow recovery of actual costs that are more than 105% of the approved revenue requirement calculated as provided in item (ii) of this subparagraph (A), except to the extent the Commission approves a modification of the Multi-Year Rate Plan to permit such recovery.
|
|
(ii) The calculation of 105% of the revenue
|
| requirement required by this subparagraph (A) shall exclude the revenue requirement impacts of the following volatile and fluctuating variables that occurred during the year: (i) storms and weather-related events for which the utility provides sufficient evidence to demonstrate that such expenses were not foreseeable and not in control of the utility; (ii) new business; (iii) changes in interest rates; (iv) changes in taxes; (v) facility relocations; (vi) changes in pension or post-retirement benefits costs due to fluctuations in interest rates, market returns or actuarial assumptions; (vii) amortization expenses related to costs; and (viii) changes in the timing of when an expenditure or investment is made such that it is accelerated to occur during the applicable year or deferred to occur in a subsequent year.
|
|
(B) the year-end rate base;
(C) the cost of equity approved in the multi-year
|
|
(D) the electric utility's actual year-end
|
| capital structure, provided that the common equity ratio in such capital structure may not exceed the common equity ratio that was approved by the Commission in the Multi-Year Rate Plan.
|
|
(2) The Commission's determinations of the prudence
|
| and reasonableness of the costs incurred for the applicable year, and of the original cost of plant in service as of the end of the applicable calendar year, shall be final upon entry of the Commission's order and shall not be subject to collateral attack in any other Commission proceeding, case, docket, order, rule, or regulation; however, nothing in this Section shall prohibit a party from petitioning the Commission to rehear or appeal to the courts the order pursuant to the provisions of this Act.
|
|
(g) 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 to conform to the Multi-Year Integrated Grid Plan ultimately approved shall not imply imprudence or unreasonableness.
(h) After calculating the Performance Adjustment and Annual Adjustment, the Commission shall order the electric utility to collect the amount in excess of the revenue requirement from customers, or issue a refund to customers, as applicable, to be applied through a surcharge beginning with the next calendar year.
Electric utilities subject to the requirements of this Section shall be permitted to file new or revised tariffs to comply with the provisions of, and Commission orders entered pursuant to, this Section.
(Source: P.A. 102-662, eff. 9-15-21.)
|
(220 ILCS 5/16-111)
Sec. 16-111. Rates and restructuring transactions during
mandatory transition period; restructuring and other transactions. (a) During the mandatory transition period,
notwithstanding any provision of Article IX of this Act, and
except as provided in subsections (b) and (f)
of this Section, the Commission shall not (i) initiate,
authorize or order any change by way of increase (other than in connection with
a request for rate increase which was filed after September 1, 1997 but prior
to October 15, 1997, by an electric utility serving less than 12,500 customers
in this State), (ii)
initiate or, unless requested by the electric utility,
authorize or order any change by way of decrease,
restructuring or unbundling (except as provided in Section 16-109A), in the
rates of any electric
utility that were in effect on October 1, 1996, or (iii) in any order approving
any application for a merger pursuant to Section 7-204 that was pending as of
May 16, 1997, impose any condition requiring any filing for an increase,
decrease, or change in, or other review of, an electric utility's rates or
enforce any such condition of any such order;
provided,
however, that this subsection shall not prohibit the
Commission from:
(1) approving the application of an electric utility |
| to implement an alternative to rate of return regulation or a regulatory mechanism that rewards or penalizes the electric utility through adjustment of rates based on utility performance, pursuant to Section 9-244;
|
|
(2) authorizing an electric utility to eliminate its
|
| fuel adjustment clause and adjust its base rate tariffs in accordance with subsection (b), (d), or (f) of Section 9-220 of this Act, to fix its fuel adjustment factor in accordance with subsection (c) of Section 9-220 of this Act, or to eliminate its fuel adjustment clause in accordance with subsection (e) of Section 9-220 of this Act;
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|
(3) ordering into effect tariffs for delivery
|
| services and transition charges in accordance with Sections 16-104 and 16-108, for real-time pricing in accordance with Section 16-107, or the options required by Section 16-110 and subsection (n) of 16-112, allowing a billing experiment in accordance with Section 16-106, or modifying delivery services tariffs in accordance with Section 16-109; or
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(4) ordering or allowing into effect any tariff to
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| recover charges pursuant to Sections 9-201.5, 9-220.1, 9-221, 9-222 (except as provided in Section 9-222.1), 16-108, and 16-114 of this Act, Section 5-5 of the Electricity Infrastructure Maintenance Fee Law, Section 6-5 of the Renewable Energy, Energy Efficiency, and Coal Resources Development Law of 1997, and Section 13 of the Energy Assistance Act.
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After December 31, 2004, the provisions of this subsection (a) shall not
apply to an electric utility whose average residential retail rate was less
than or equal to 90% of the average residential retail rate for the "Midwest
Utilities", as that term is defined in subsection (b) of this Section, based on
data reported on Form 1 to the Federal Energy Regulatory Commission for
calendar year 1995, and which served between 150,000 and 250,000 retail
customers in this State on January 1, 1995
unless the electric utility or its holding company has been acquired by or
merged with an affiliate of another electric utility subsequent to January 1,
2002. This exemption shall be limited to
this subsection (a) and shall not extend to any other provisions of this Act.
(b) Notwithstanding the provisions of subsection (a), each Illinois electric
utility serving more than 12,500 customers in Illinois shall file tariffs (i)
reducing, effective August 1, 1998, each component of its base rates to
residential retail
customers by 15% from the base rates in effect immediately prior to January 1,
1998 and (ii) if the public utility provides electric service to (A) more
than
500,000
customers but less than 1,000,000 customers in this State on January 1,
1999,
reducing, effective May 1, 2002, each component of its
base rates to residential retail customers by an additional 5% from the base
rates in effect immediately prior to January 1, 1998, or (B) at least
1,000,000 customers in this State on January 1, 1999,
reducing, effective October 1, 2001, each component of its
base rates to residential retail customers by an additional
5% from the base rates in effect immediately prior to
January 1, 1998.
Provided, however, that (A) if an electric utility's average residential
retail
rate is less than or equal to the average residential retail
rate for a group
of Midwest Utilities (consisting of all investor-owned electric utilities with
annual system peaks in excess of 1000 megawatts in the States of Illinois,
Indiana, Iowa, Kentucky, Michigan, Missouri, Ohio, and Wisconsin), based on
data
reported on Form 1 to the Federal Energy Regulatory Commission for calendar
year 1995,
then it shall only be required to file tariffs (i) reducing, effective August
1, 1998, each component of its base rates to residential
retail customers by
5% from the base rates in effect immediately prior to January 1, 1998, (ii)
reducing, effective October 1, 2000, each component of its base
rates to residential retail customers by the lesser of 5% of the base rates in
effect immediately prior to January 1, 1998 or the
percentage by which the electric utility's average residential retail rate
exceeds the average residential retail rate of the Midwest Utilities,
based on data
reported on Form 1 to the Federal Energy Regulatory Commission for calendar
year 1999, and (iii) reducing, effective October 1, 2002, each component of its
base rates to
residential retail customers by an
additional amount equal to the lesser of 5% of the base rates in effect
immediately prior to January 1, 1998 or the percentage by which
the electric utility's average residential retail rate exceeds the average
residential retail rate of the Midwest Utilities,
based on data reported on Form
1 to the Federal Energy Regulatory Commission for calendar year 2001; and (B)
if the average residential retail rate of an electric utility serving between
150,000
and 250,000 retail customers in this State on January 1, 1995 is less than or
equal to 90% of
the average residential retail rate for the Midwest Utilities, based on data
reported
on Form 1 to the Federal Energy Regulatory Commission for calendar year 1995,
then it shall only be required to file tariffs (i) reducing, effective August
1,
1998, each component of its base rates to residential retail customers by 2%
from the base rates in effect immediately prior to January 1, 1998; (ii)
reducing, effective October 1, 2000, each component of its base rates to
residential retail customers by 2% from the base rate in effect immediately
prior to January 1, 1998; and (iii) reducing, effective October 1, 2002, each
component of its base rates to residential retail customers by 1% from the base
rates in effect immediately prior to January 1, 1998.
Provided,
further, that any electric utility for which a decrease in base rates has been
or is placed into effect between October 1, 1996 and the dates specified in the
preceding sentences of this subsection, other than pursuant to the requirements
of this subsection,
shall be entitled to reduce the amount of any reduction or reductions in its
base rates required by this subsection by the amount of such other decrease.
The tariffs required under this
subsection shall be filed 45 days in advance of
the effective date.
Notwithstanding anything to the contrary in Section 9-220 of this Act, no
restatement of base rates in conjunction with the elimination of a fuel
adjustment clause under that Section shall result in a lesser decrease in base
rates than customers would otherwise receive under this subsection had the
electric utility's fuel adjustment clause not been eliminated.
(c) Any utility reducing its base rates by 15% on August 1, 1998 pursuant
to
subsection
(b)
shall include the following statement on its bills for residential customers
from August 1 through December 31, 1998: "Effective August 1, 1998, your rates
have been
reduced by 15% by the Electric Service
Customer Choice and Rate Relief Law of 1997 passed by the Illinois General
Assembly.". Any utility reducing its base rates by 5% on August 1, 1998,
pursuant to subsection (b) shall include the following statement on its bills
for residential customers from August 1 through December 31, 1998: "Effective
August 1,
1998, your rates have been reduced by 5% by the Electric Service Customer
Choice and Rate Relief Law of 1997 passed by the Illinois General Assembly.".
Any utility reducing its base rates by 2% on August 1, 1998 pursuant to
subsection (b) shall include the following statement on its bills for
residential customers from August 1 through December 31, 1998: "Effective
August 1, 1998, your rates have been reduced by 2% by the Electric Service
Customer Choice and Rate Relief Law of 1997 passed by the Illinois General
Assembly.".
(d) (Blank.)
(e) (Blank.)
(f) During the mandatory transition period, an electric
utility may file revised tariffs reducing the price of any
tariffed service offered by the electric utility for all
customers taking that tariffed service, which shall be
effective 7 days after filing.
(g) Until all classes of tariffed services are declared competitive, an electric
utility may, without obtaining any approval of the Commission other than that
provided for in this subsection and
notwithstanding any other provision of this Act or any rule or
regulation of the Commission that would require such approval:
(1) implement a reorganization, other than a merger
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| of 2 or more public utilities as defined in Section 3-105 or their holding companies;
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(2) retire generating plants from service;
(3) sell, assign, lease or otherwise transfer assets
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| to an affiliated or unaffiliated entity and as part of such transaction enter into service agreements, power purchase agreements, or other agreements with the transferee; provided, however, that the prices, terms and conditions of any power purchase agreement must be approved or allowed into effect by the Federal Energy Regulatory Commission; or
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(4) use any accelerated cost recovery method
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| including accelerated depreciation, accelerated amortization or other capital recovery methods, or record reductions to the original cost of its assets.
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In order to implement a reorganization, retire
generating plants from service, or sell, assign, lease or
otherwise transfer assets pursuant to this Section, the
electric utility shall comply with subsections (c) and (d) of Section
16-128, if applicable, and subsection (k) of this Section, if applicable,
and provide the Commission with at
least 30 days notice of the proposed reorganization or
transaction, which notice shall include the following
information:
(i) a complete statement of the entries that the
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| electric utility will make on its books and records of account to implement the proposed reorganization or transaction together with a certification from an independent certified public accountant that such entries are in accord with generally accepted accounting principles and, if the Commission has previously approved guidelines for cost allocations between the utility and its affiliates, a certification from the chief accounting officer of the utility that such entries are in accord with those cost allocation guidelines;
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(ii) a description of how the electric utility will
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| use proceeds of any sale, assignment, lease or transfer to retire debt or otherwise reduce or recover the costs of services provided by such electric utility;
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(iii) a list of all federal approvals or approvals
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| required from departments and agencies of this State, other than the Commission, that the electric utility has or will obtain before implementing the reorganization or transaction;
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(iv) an irrevocable commitment by the electric
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| utility that it will not, as a result of the transaction, impose any stranded cost charges that it might otherwise be allowed to charge retail customers under federal law or increase the transition charges that it is otherwise entitled to collect under this Article XVI;
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(v) if the electric utility proposes to sell, assign,
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| lease or otherwise transfer a generating plant that brings the amount of net dependable generating capacity transferred pursuant to this subsection to an amount equal to or greater than 15% of the electric utility's net dependable capacity as of the effective date of this amendatory Act of 1997, and enters into a power purchase agreement with the entity to which such generating plant is sold, assigned, leased, or otherwise transferred, the electric utility also agrees, if its fuel adjustment clause has not already been eliminated, to eliminate its fuel adjustment clause in accordance with subsection (b) of Section 9-220 for a period of time equal to the length of any such power purchase agreement or successor agreement, or until January 1, 2005, whichever is longer; if the capacity of the generating plant so transferred and related power purchase agreement does not result in the elimination of the fuel adjustment clause under this subsection, and the fuel adjustment clause has not already been eliminated, the electric utility shall agree that the costs associated with the transferred plant that are included in the calculation of the rate per kilowatt-hour to be applied pursuant to the electric utility's fuel adjustment clause during such period shall not exceed the per kilowatt-hour cost associated with such generating plant included in the electric utility's fuel adjustment clause during the full calendar year preceding the transfer, with such limit to be adjusted each year thereafter by the Gross Domestic Product Implicit Price Deflator; and
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|
(vi) in addition, if the electric utility proposes
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| to sell, assign, or lease, (A) either (1) an amount of generating plant that brings the amount of net dependable generating capacity transferred pursuant to this subsection to an amount equal to or greater than 15% of its net dependable capacity on the effective date of this amendatory Act of 1997, or (2) one or more generating plants with a total net dependable capacity of 1100 megawatts, or (B) transmission and distribution facilities that either (1) bring the amount of transmission and distribution facilities transferred pursuant to this subsection to an amount equal to or greater than 15% of the electric utility's total depreciated original cost investment in such facilities, or (2) represent an investment of $25,000,000 in terms of total depreciated original cost, the electric utility shall provide, in addition to the information listed in subparagraphs (i) through (v), the following information: (A) a description of how the electric utility will meet its service obligations under this Act in a safe and reliable manner and (B) the electric utility's projected earned rate of return on common equity for each year from the date of the notice through December 31, 2006 both with and without the proposed transaction. If the Commission has not issued an order initiating a hearing on the proposed transaction within 30 days after the date the electric utility's notice is filed, the transaction shall be deemed approved. The Commission may, after notice and hearing, prohibit the proposed transaction if it makes either or both of the following findings: (1) that the proposed transaction will render the electric utility unable to provide its tariffed services in a safe and reliable manner, or (2) that there is a strong likelihood that consummation of the proposed transaction will result in the electric utility being entitled to request an increase in its base rates. Any hearing initiated by the Commission into the proposed transaction shall be completed, and the Commission's final order approving or prohibiting the proposed transaction shall be entered, within 90 days after the date the electric utility's notice was filed. Provided, however, that a sale, assignment, or lease of transmission facilities to an independent system operator that meets the requirements of Section 16-126 shall not be subject to Commission approval under this Section.
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|
In any proceeding conducted by the Commission
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| pursuant to this subparagraph (vi), intervention shall be limited to parties with a direct interest in the transaction which is the subject of the hearing and any statutory consumer protection agency as defined in subsection (d) of Section 9-102.1. Notwithstanding the provisions of Section 10-113 of this Act, any application seeking rehearing of an order issued under this subparagraph (vi), whether filed by the electric utility or by an intervening party, shall be filed within 10 days after service of the order.
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|
The Commission shall not in any subsequent proceeding or
otherwise, review such a reorganization or other transaction
authorized by this Section, but shall retain the authority to allocate costs as
stated in Section 16-111(i). An entity to which an electric
utility sells, assigns, leases or transfers assets pursuant to
this subsection (g) shall not, as a result of the transactions
specified in this subsection (g), be deemed a public utility
as defined in Section 3-105. Nothing in this subsection (g)
shall change any requirement under the jurisdiction of the
Illinois Department of Nuclear Safety including, but not
limited to, the payment of fees. Nothing in this subsection
(g) shall exempt a utility from obtaining a certificate
pursuant to Section 8-406 of this Act for the construction of
a new electric generating facility. Nothing in this
subsection (g) is intended to exempt the transactions hereunder from the
operation of the federal or State antitrust
laws. Nothing in this subsection (g) shall require an electric
utility to use the procedures specified in this subsection for
any of the transactions specified herein. Any other procedure
available under this Act may, at the electric utility's
election, be used for any such transaction.
(h) During the mandatory transition period, the
Commission shall not establish or use any rates of
depreciation, which for purposes of this subsection shall
include amortization, for any electric utility other than
those established pursuant to subsection (c) of Section 5-104
of this Act or utilized pursuant to subsection (g) of this
Section. Provided, however, that in any proceeding to review an electric
utility's rates for tariffed services pursuant to Section 9-201, 9-202, 9-250
or
16-111(d) of this Act, the Commission may establish new rates
of depreciation for the electric utility in the same manner provided in
subsection (d) of Section 5-104 of this Act.
An electric utility implementing an accelerated cost
recovery method including accelerated depreciation,
accelerated amortization or other capital recovery methods, or
recording reductions to the original cost of its assets,
pursuant to subsection (g) of this Section, shall file a
statement with the Commission describing the accelerated cost
recovery method to be implemented or the reduction in the
original cost of its assets to be recorded. Upon the filing
of such statement, the accelerated cost recovery method or the
reduction in the original cost of assets shall be deemed to be
approved by the Commission as though an order had been entered
by the Commission.
(i) Subsequent to the mandatory transition period, the
Commission, in any proceeding to establish rates and charges
for tariffed services offered by an electric utility, shall
consider only (1) the then current or projected revenues,
costs, investments and cost of capital directly or
indirectly associated with the provision of such tariffed
services; (2) collection of transition charges in accordance
with Sections 16-102 and 16-108 of this Act; (3) recovery of
any employee transition costs as described in Section 16-128
which the electric utility is continuing to incur, including
recovery of any unamortized portion of such costs previously
incurred or committed, with such costs to be equitably
allocated among bundled services, delivery services, and
contracts with alternative retail electric suppliers; and (4)
recovery of the costs associated with the electric utility's
compliance with decommissioning funding requirements; and
shall not consider any other revenues, costs, investments
or cost of capital of either the electric utility or of any
affiliate of the electric utility that are not associated with the provision of
tariffed services. In setting rates for tariffed services, the Commission
shall equitably allocate joint and common costs and investments between the
electric utility's competitive and tariffed services. In determining the
justness and
reasonableness of the electric power and energy component of
an electric utility's rates for tariffed services subsequent
to the mandatory transition period and prior to the time that
the provision of such electric power and energy is declared
competitive, the Commission shall consider the extent to which
the electric utility's tariffed rates for such component for
each customer class exceed the market value determined
pursuant to Section 16-112, and, if the electric power and
energy component of such tariffed rate exceeds the market
value by more than 10% for any customer class, may
establish such electric power and energy component at a rate
equal to the market value plus 10%.
(j) During the mandatory transition period, an electric
utility may elect to transfer to a non-operating income
account under the Commission's Uniform System of Accounts
either or both of (i) an amount of unamortized investment tax
credit that is in addition to the ratable amount which is
credited to the electric utility's operating income account
for the year in accordance with Section 46(f)(2) of the
federal Internal Revenue Code of 1986, as in effect prior to P.L. 101-508, or
(ii) "excess tax reserves",
as that term is defined in Section 203(e)(2)(A) of the federal
Tax Reform Act of 1986, provided that (A) the amount
transferred may not exceed the amount of the electric
utility's assets that were created pursuant to Statement of
Financial Accounting Standards No. 71 which the electric
utility has written off during the mandatory transition
period, and (B) the transfer shall not be effective until
approved by the Internal Revenue Service. An electric utility
electing to make such a transfer shall file a statement with
the Commission stating the amount and timing of the transfer
for which it intends to request approval of the Internal
Revenue Service, along with a copy of its proposed request to
the Internal Revenue Service for a ruling. The Commission
shall issue an order within 14 days after the electric
utility's filing approving, subject to receipt of approval
from the Internal Revenue Service, the proposed transfer.
(k) If an electric utility is selling or transferring
to a single buyer 5 or more generating plants located in this State with a
total net dependable capacity of 5000 megawatts or more
pursuant to subsection (g) of this Section and has obtained
a sale price or consideration that exceeds 200% of
the book value of such plants, the electric utility must
provide to the Governor, the President of the Illinois
Senate, the Minority Leader of the Illinois Senate, the
Speaker of the Illinois House of Representatives, and the
Minority Leader of the Illinois House of Representatives no
later than 15 days after filing its notice under subsection
(g) of this Section or 5 days after the date on which this
subsection (k) becomes law, whichever is later, a written
commitment in which such electric utility agrees to expend
$2 billion outside the corporate limits of any municipality
with 1,000,000 or more inhabitants within such electric
utility's service area, over a 6-year period beginning
with the calendar year in which the notice is filed, on
projects, programs, and improvements within its service area
relating to transmission and distribution including, without
limitation, infrastructure expansion, repair and
replacement, capital investments, operations and
maintenance, and vegetation management.
(l) Notwithstanding any other provision of this Act or any rule, regulation, or prior order of the Commission, a public utility providing electric and gas service may do any one or more of the following: transfer assets to, reorganize with, or merge with one or more public utilities under common holding company ownership or control in the manner prescribed in subsection (g) of this Section. No merger transaction costs, such as fees paid to attorneys, investment bankers, and other consultants, incurred in connection with a merger pursuant to this subsection (l) shall be recoverable in any subsequent rate proceeding. Approval of a merger pursuant to this subsection (l) shall not constitute approval of, or otherwise require, rate recovery of other costs incurred in connection with, or to implement the merger, such as the cost of restructuring, combining, or integrating debt, assets, or systems. Such other costs may be recovered only to the extent that the surviving utility can demonstrate that the cost savings produced by such restructuring, combination, or integration exceed the associated costs. Nothing in this subsection (l) shall impair the terms or conditions of employment or the collective bargaining rights of any employees of the utilities that are transferring assets, reorganizing, or merging.
(m) If an electric utility that on December 31, 2005 provided electric service to at least 100,000 customers in Illinois transfers assets, reorganizes, or merges under this Section, then the same provisions apply that applied during the mandatory transition period under Section 16-128.
(Source: P.A. 95-331, eff. 8-21-07; 95-481, eff. 8-28-07; 95-876, eff. 8-21-08.)
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(220 ILCS 5/16-111.5) Sec. 16-111.5. Provisions relating to procurement. (a) An electric utility that on December 31, 2005 served at least 100,000 customers in Illinois shall procure power and energy for its eligible retail customers in accordance with the applicable provisions set forth in Section 1-75 of the Illinois Power Agency Act and this Section. Beginning with the delivery year commencing on June 1, 2017, such electric utility shall also procure zero emission credits from zero emission facilities in accordance with the applicable provisions set forth in Section 1-75 of the Illinois Power Agency Act, and, for years beginning on or after June 1, 2017, the utility shall procure renewable energy resources in accordance with the applicable provisions set forth in Section 1-75 of the Illinois Power Agency Act and this Section. Beginning with the delivery year commencing on June 1, 2022, an electric utility serving over 3,000,000 customers shall also procure carbon mitigation credits from carbon-free energy resources in accordance with the applicable provisions set forth in Section 1-75 of the Illinois Power Agency Act and this Section. A small multi-jurisdictional electric utility that on December 31, 2005 served less than 100,000 customers in Illinois may elect to procure power and energy for all or a portion of its eligible Illinois retail customers in accordance with the applicable provisions set forth in this Section and Section 1-75 of the Illinois Power Agency Act. This Section shall not apply to a small multi-jurisdictional utility until such time as a small multi-jurisdictional utility requests the Illinois Power Agency to prepare a procurement plan for its eligible retail customers. "Eligible retail customers" for the purposes of this Section means those retail customers that purchase power and energy from the electric utility under fixed-price bundled service tariffs, other than those retail customers whose service is declared or deemed competitive under Section 16-113 and those other customer groups specified in this Section, including self-generating customers, customers electing hourly pricing, or those customers who are otherwise ineligible for fixed-price bundled tariff service. For those customers that are excluded from the procurement plan's electric supply service requirements, and the utility shall procure any supply requirements, including capacity, ancillary services, and hourly priced energy, in the applicable markets as needed to serve those customers, provided that the utility may include in its procurement plan load requirements for the load that is associated with those retail customers whose service has been declared or deemed competitive pursuant to Section 16-113 of this Act to the extent that those customers are purchasing power and energy during one of the transition periods identified in subsection (b) of Section 16-113 of this Act. (b) A procurement plan shall be prepared for each electric utility consistent with the applicable requirements of the Illinois Power Agency Act and this Section. For purposes of this Section, Illinois electric utilities that are affiliated by virtue of a common parent company are considered to be a single electric utility. Small multi-jurisdictional utilities may request a procurement plan for a portion of or all of its Illinois load. Each procurement plan shall analyze the projected balance of supply and demand for those retail customers to be included in the plan's electric supply service requirements over a 5-year period, with the first planning year beginning on June 1 of the year following the year in which the plan is filed. The plan shall specifically identify the wholesale products to be procured following plan approval, and shall follow all the requirements set forth in the Public Utilities Act and all applicable State and federal laws, statutes, rules, or regulations, as well as Commission orders. Nothing in this Section precludes consideration of contracts longer than 5 years and related forecast data. Unless specified otherwise in this Section, in the procurement plan or in the implementing tariff, any procurement occurring in accordance with this plan shall be competitively bid through a request for proposals process. Approval and implementation of the procurement plan shall be subject to review and approval by the Commission according to the provisions set forth in this Section. A procurement plan shall include each of the following components: (1) Hourly load analysis. This analysis shall |
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(i) multi-year historical analysis of hourly
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(ii) switching trends and competitive retail
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(iii) known or projected changes to future loads;
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(iv) growth forecasts by customer class.
(2) Analysis of the impact of any demand side and
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| renewable energy initiatives. This analysis shall include:
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(i) the impact of demand response programs and
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| energy efficiency programs, both current and projected; for small multi-jurisdictional utilities, the impact of demand response and energy efficiency programs approved pursuant to Section 8-408 of this Act, both current and projected; and
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(ii) supply side needs that are projected to be
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| offset by purchases of renewable energy resources, if any.
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(3) A plan for meeting the expected load requirements
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| that will not be met through preexisting contracts. This plan shall include:
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(i) definitions of the different Illinois retail
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| customer classes for which supply is being purchased;
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(ii) the proposed mix of demand-response products
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| for which contracts will be executed during the next year. For small multi-jurisdictional electric utilities that on December 31, 2005 served fewer than 100,000 customers in Illinois, these shall be defined as demand-response products offered in an energy efficiency plan approved pursuant to Section 8-408 of this Act. The cost-effective demand-response measures shall be procured whenever the cost is lower than procuring comparable capacity products, provided that such products shall:
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(A) be procured by a demand-response provider
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| from those retail customers included in the plan's electric supply service requirements;
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(B) at least satisfy the demand-response
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| requirements of the regional transmission organization market in which the utility's service territory is located, including, but not limited to, any applicable capacity or dispatch requirements;
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(C) provide for customers' participation in
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| the stream of benefits produced by the demand-response products;
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(D) provide for reimbursement by the
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| demand-response provider of the utility for any costs incurred as a result of the failure of the supplier of such products to perform its obligations thereunder; and
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(E) meet the same credit requirements as
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| apply to suppliers of capacity, in the applicable regional transmission organization market;
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(iii) monthly forecasted system supply
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| requirements, including expected minimum, maximum, and average values for the planning period;
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(iv) the proposed mix and selection of standard
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| wholesale products for which contracts will be executed during the next year, separately or in combination, to meet that portion of its load requirements not met through pre-existing contracts, including but not limited to monthly 5 x 16 peak period block energy, monthly off-peak wrap energy, monthly 7 x 24 energy, annual 5 x 16 energy, other standardized energy or capacity products designed to provide eligible retail customer benefits from commercially deployed advanced technologies including but not limited to high voltage direct current converter stations, as such term is defined in Section 1-10 of the Illinois Power Agency Act, whether or not such product is currently available in wholesale markets, annual off-peak wrap energy, annual 7 x 24 energy, monthly capacity, annual capacity, peak load capacity obligations, capacity purchase plan, and ancillary services;
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(v) proposed term structures for each wholesale
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| product type included in the proposed procurement plan portfolio of products; and
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(vi) an assessment of the price risk, load
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| uncertainty, and other factors that are associated with the proposed procurement plan; this assessment, to the extent possible, shall include an analysis of the following factors: contract terms, time frames for securing products or services, fuel costs, weather patterns, transmission costs, market conditions, and the governmental regulatory environment; the proposed procurement plan shall also identify alternatives for those portfolio measures that are identified as having significant price risk and mitigation in the form of additional retail customer and ratepayer price, reliability, and environmental benefits from standardized energy products delivered from commercially deployed advanced technologies, including, but not limited to, high voltage direct current converter stations, as such term is defined in Section 1-10 of the Illinois Power Agency Act, whether or not such product is currently available in wholesale markets.
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(4) Proposed procedures for balancing loads. The
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| procurement plan shall include, for load requirements included in the procurement plan, the process for (i) hourly balancing of supply and demand and (ii) the criteria for portfolio re-balancing in the event of significant shifts in load.
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(5) Long-Term Renewable Resources Procurement
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| Plan. The Agency shall prepare a long-term renewable resources procurement plan for the procurement of renewable energy credits under Sections 1-56 and 1-75 of the Illinois Power Agency Act for delivery beginning in the 2017 delivery year.
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(i) The initial long-term renewable
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| resources procurement plan and all subsequent revisions shall be subject to review and approval by the Commission. For the purposes of this Section, "delivery year" has the same meaning as in Section 1-10 of the Illinois Power Agency Act. For purposes of this Section, "Agency" shall mean the Illinois Power Agency.
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(ii) The long-term renewable resources
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| planning process shall be conducted as follows:
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(A) Electric utilities shall provide a
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| range of load forecasts to the Illinois Power Agency within 45 days of the Agency's request for forecasts, which request shall specify the length and conditions for the forecasts including, but not limited to, the quantity of distributed generation expected to be interconnected for each year.
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(B) The Agency shall publish for comment
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| the initial long-term renewable resources procurement plan no later than 120 days after the effective date of this amendatory Act of the 99th General Assembly and shall review, and may revise, the plan at least every 2 years thereafter. To the extent practicable, the Agency shall review and propose any revisions to the long-term renewable energy resources procurement plan in conjunction with the Agency's other planning and approval processes conducted under this Section. The initial long-term renewable resources procurement plan shall:
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(aa) Identify the procurement
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| programs and competitive procurement events consistent with the applicable requirements of the Illinois Power Agency Act and shall be designed to achieve the goals set forth in subsection (c) of Section 1-75 of that Act.
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(bb) Include a schedule for
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| procurements for renewable energy credits from utility-scale wind projects, utility-scale solar projects, and brownfield site photovoltaic projects consistent with subparagraph (G) of paragraph (1) of subsection (c) of Section 1-75 of the Illinois Power Agency Act.
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(cc) Identify the process whereby
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| the Agency will submit to the Commission for review and approval the proposed contracts to implement the programs required by such plan.
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Copies of the initial long-term renewable
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| resources procurement plan and all subsequent revisions shall be posted and made publicly available on the Agency's and Commission's websites, and copies shall also be provided to each affected electric utility. An affected utility and other interested parties shall have 45 days following the date of posting to provide comment to the Agency on the initial long-term renewable resources procurement plan and all subsequent revisions. All comments submitted to the Agency shall be specific, supported by data or other detailed analyses, and, if objecting to all or a portion of the procurement plan, accompanied by specific alternative wording or proposals. All comments shall be posted on the Agency's and Commission's websites. During this 45-day comment period, the Agency shall hold at least one public hearing within each utility's service area that is subject to the requirements of this paragraph (5) for the purpose of receiving public comment. Within 21 days following the end of the 45-day review period, the Agency may revise the long-term renewable resources procurement plan based on the comments received and shall file the plan with the Commission for review and approval.
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(C) Within 14 days after the filing of the
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| initial long-term renewable resources procurement plan or any subsequent revisions, any person objecting to the plan may file an objection with the Commission. Within 21 days after the filing of the plan, the Commission shall determine whether a hearing is necessary. The Commission shall enter its order confirming or modifying the initial long-term renewable resources procurement plan or any subsequent revisions within 120 days after the filing of the plan by the Illinois Power Agency.
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(D) The Commission shall approve the
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| initial long-term renewable resources procurement plan and any subsequent revisions, including expressly the forecast used in the plan and taking into account that funding will be limited to the amount of revenues actually collected by the utilities, if the Commission determines that the plan will reasonably and prudently accomplish the requirements of Section 1-56 and subsection (c) of Section 1-75 of the Illinois Power Agency Act. The Commission shall also approve the process for the submission, review, and approval of the proposed contracts to procure renewable energy credits or implement the programs authorized by the Commission pursuant to a long-term renewable resources procurement plan approved under this Section.
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In approving any long-term renewable
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| resources procurement plan after the effective date of this amendatory Act of the 102nd General Assembly, the Commission shall approve or modify the Agency's proposal for minimum equity standards pursuant to subsection (c-10) of Section 1-75 of the Illinois Power Agency Act. The Commission shall consider any analysis performed by the Agency in developing its proposal, including past performance, availability of equity eligible contractors, and availability of equity eligible persons at the time the long-term renewable resources procurement plan is approved.
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(iii) The Agency or third parties contracted
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| by the Agency shall implement all programs authorized by the Commission in an approved long-term renewable resources procurement plan without further review and approval by the Commission. Third parties shall not begin implementing any programs or receive any payment under this Section until the Commission has approved the contract or contracts under the process authorized by the Commission in item (D) of subparagraph (ii) of paragraph (5) of this subsection (b) and the third party and the Agency or utility, as applicable, have executed the contract. For those renewable energy credits subject to procurement through a competitive bid process under the plan or under the initial forward procurements for wind and solar resources described in subparagraph (G) of paragraph (1) of subsection (c) of Section 1-75 of the Illinois Power Agency Act, the Agency shall follow the procurement process specified in the provisions relating to electricity procurement in subsections (e) through (i) of this Section.
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(iv) An electric utility shall recover its
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| costs associated with the procurement of renewable energy credits under this Section and pursuant to subsection (c-5) of Section 1-75 of the Illinois Power Agency Act through an automatic adjustment clause tariff under subsection (k) or a tariff pursuant to subsection (i-5), as applicable, of Section 16-108 of this Act. A utility shall not be required to advance any payment or pay any amounts under this Section that exceed the actual amount of revenues collected by the utility under paragraph (6) of subsection (c) of Section 1-75 of the Illinois Power Agency Act, subsection (c-5) of Section 1-75 of the Illinois Power Agency Act, and subsection (k) or subsection (i-5), as applicable, of Section 16-108 of this Act, and contracts executed under this Section shall expressly incorporate this limitation.
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(v) For the public interest, safety, and
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| welfare, the Agency and the Commission may adopt rules to carry out the provisions of this Section on an emergency basis immediately following the effective date of this amendatory Act of the 99th General Assembly.
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(vi) On or before July 1 of each year, the
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| Commission shall hold an informal hearing for the purpose of receiving comments on the prior year's procurement process and any recommendations for change.
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(b-5) An electric utility that as of January 1, 2019 served more than 300,000 retail customers in this State shall purchase renewable energy credits from new renewable energy facilities constructed at or adjacent to the sites of coal-fueled electric generating facilities in this State in accordance with subsection (c-5) of Section 1-75 of the Illinois Power Agency Act. Except as expressly provided in this Section, the plans and procedures for such procurements shall not be included in the procurement plans provided for in this Section, but rather shall be conducted and implemented solely in accordance with subsection (c-5) of Section 1-75 of the Illinois Power Agency Act.
(c) The provisions of this subsection (c) shall not apply to procurements conducted pursuant to subsection (c-5) of Section 1-75 of the Illinois Power Agency Act. However, the Agency may retain a procurement administrator to assist the Agency in planning and carrying out the procurement events and implementing the other requirements specified in such subsection (c-5) of Section 1-75 of the Illinois Power Agency Act, with the costs incurred by the Agency for the procurement administrator to be recovered through fees charged to applicants for selection to sell and deliver renewable energy credits to electric utilities pursuant to subsection (c-5) of Section 1-75 of the Illinois Power Agency Act. The procurement process set forth in Section 1-75 of the Illinois Power Agency Act and subsection (e) of this Section shall be administered by a procurement administrator and monitored by a procurement monitor.
(1) The procurement administrator shall:
(i) design the final procurement process in
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| accordance with Section 1-75 of the Illinois Power Agency Act and subsection (e) of this Section following Commission approval of the procurement plan;
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(ii) develop benchmarks in accordance with
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| subsection (e)(3) to be used to evaluate bids; these benchmarks shall be submitted to the Commission for review and approval on a confidential basis prior to the procurement event;
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(iii) serve as the interface between the electric
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(iv) manage the bidder pre-qualification and
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(v) obtain the electric utilities' agreement to
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| the final form of all supply contracts and credit collateral agreements;
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(vi) administer the request for proposals process;
(vii) have the discretion to negotiate to
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| determine whether bidders are willing to lower the price of bids that meet the benchmarks approved by the Commission; any post-bid negotiations with bidders shall be limited to price only and shall be completed within 24 hours after opening the sealed bids and shall be conducted in a fair and unbiased manner; in conducting the negotiations, there shall be no disclosure of any information derived from proposals submitted by competing bidders; if information is disclosed to any bidder, it shall be provided to all competing bidders;
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(viii) maintain confidentiality of supplier and
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| bidding information in a manner consistent with all applicable laws, rules, regulations, and tariffs;
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(ix) submit a confidential report to the
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| Commission recommending acceptance or rejection of bids;
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(x) notify the utility of contract counterparties
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| and contract specifics; and
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(xi) administer related contingency procurement
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(2) The procurement monitor, who shall be retained by
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(i) monitor interactions among the procurement
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| administrator, suppliers, and utility;
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(ii) monitor and report to the Commission on the
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| progress of the procurement process;
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(iii) provide an independent confidential report
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| to the Commission regarding the results of the procurement event;
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(iv) assess compliance with the procurement plans
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| approved by the Commission for each utility that on December 31, 2005 provided electric service to at least 100,000 customers in Illinois and for each small multi-jurisdictional utility that on December 31, 2005 served less than 100,000 customers in Illinois;
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(v) preserve the confidentiality of supplier and
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| bidding information in a manner consistent with all applicable laws, rules, regulations, and tariffs;
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(vi) provide expert advice to the Commission and
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| consult with the procurement administrator regarding issues related to procurement process design, rules, protocols, and policy-related matters; and
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(vii) consult with the procurement administrator
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| regarding the development and use of benchmark criteria, standard form contracts, credit policies, and bid documents.
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(d) Except as provided in subsection (j), the planning process shall be conducted as follows:
(1) Beginning in 2008, each Illinois utility
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| procuring power pursuant to this Section shall annually provide a range of load forecasts to the Illinois Power Agency by July 15 of each year, or such other date as may be required by the Commission or Agency. The load forecasts shall cover the 5-year procurement planning period for the next procurement plan and shall include hourly data representing a high-load, low-load, and expected-load scenario for the load of those retail customers included in the plan's electric supply service requirements. The utility shall provide supporting data and assumptions for each of the scenarios.
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(2) Beginning in 2008, the Illinois Power Agency
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| shall prepare a procurement plan by August 15th of each year, or such other date as may be required by the Commission. The procurement plan shall identify the portfolio of demand-response and power and energy products to be procured. Cost-effective demand-response measures shall be procured as set forth in item (iii) of subsection (b) of this Section. Copies of the procurement plan shall be posted and made publicly available on the Agency's and Commission's websites, and copies shall also be provided to each affected electric utility. An affected utility shall have 30 days following the date of posting to provide comment to the Agency on the procurement plan. Other interested entities also may comment on the procurement plan. All comments submitted to the Agency shall be specific, supported by data or other detailed analyses, and, if objecting to all or a portion of the procurement plan, accompanied by specific alternative wording or proposals. All comments shall be posted on the Agency's and Commission's websites. During this 30-day comment period, the Agency shall hold at least one public hearing within each utility's service area for the purpose of receiving public comment on the procurement plan. Within 14 days following the end of the 30-day review period, the Agency shall revise the procurement plan as necessary based on the comments received and file the procurement plan with the Commission and post the procurement plan on the websites.
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(3) Within 5 days after the filing of the procurement
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| plan, any person objecting to the procurement plan shall file an objection with the Commission. Within 10 days after the filing, the Commission shall determine whether a hearing is necessary. The Commission shall enter its order confirming or modifying the procurement plan within 90 days after the filing of the procurement plan by the Illinois Power Agency.
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(4) The Commission shall approve the procurement
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| plan, including expressly the forecast used in the procurement plan, if the Commission determines that it will ensure adequate, reliable, affordable, efficient, and environmentally sustainable electric service at the lowest total cost over time, taking into account any benefits of price stability.
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(4.5) The Commission shall review the Agency's
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| recommendations for the selection of applicants to enter into long-term contracts for the sale and delivery of renewable energy credits from new renewable energy facilities to be constructed at or adjacent to the sites of coal-fueled electric generating facilities in this State in accordance with the provisions of subsection (c-5) of Section 1-75 of the Illinois Power Agency Act, and shall approve the Agency's recommendations if the Commission determines that the applicants recommended by the Agency for selection, the proposed new renewable energy facilities to be constructed, the amounts of renewable energy credits to be delivered pursuant to the contracts, and the other terms of the contracts, are consistent with the requirements of subsection (c-5) of Section 1-75 of the Illinois Power Agency Act.
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(e) The procurement process shall include each of the following components:
(1) Solicitation, pre-qualification, and registration
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| of bidders. The procurement administrator shall disseminate information to potential bidders to promote a procurement event, notify potential bidders that the procurement administrator may enter into a post-bid price negotiation with bidders that meet the applicable benchmarks, provide supply requirements, and otherwise explain the competitive procurement process. In addition to such other publication as the procurement administrator determines is appropriate, this information shall be posted on the Illinois Power Agency's and the Commission's websites. The procurement administrator shall also administer the prequalification process, including evaluation of credit worthiness, compliance with procurement rules, and agreement to the standard form contract developed pursuant to paragraph (2) of this subsection (e). The procurement administrator shall then identify and register bidders to participate in the procurement event.
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(2) Standard contract forms and credit terms and
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| instruments. The procurement administrator, in consultation with the utilities, the Commission, and other interested parties and subject to Commission oversight, shall develop and provide standard contract forms for the supplier contracts that meet generally accepted industry practices. Standard credit terms and instruments that meet generally accepted industry practices shall be similarly developed. The procurement administrator shall make available to the Commission all written comments it receives on the contract forms, credit terms, or instruments. If the procurement administrator cannot reach agreement with the applicable electric utility as to the contract terms and conditions, the procurement administrator must notify the Commission of any disputed terms and the Commission shall resolve the dispute. The terms of the contracts shall not be subject to negotiation by winning bidders, and the bidders must agree to the terms of the contract in advance so that winning bids are selected solely on the basis of price.
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(3) Establishment of a market-based price benchmark.
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| As part of the development of the procurement process, the procurement administrator, in consultation with the Commission staff, Agency staff, and the procurement monitor, shall establish benchmarks for evaluating the final prices in the contracts for each of the products that will be procured through the procurement process. The benchmarks shall be based on price data for similar products for the same delivery period and same delivery hub, or other delivery hubs after adjusting for that difference. The price benchmarks may also be adjusted to take into account differences between the information reflected in the underlying data sources and the specific products and procurement process being used to procure power for the Illinois utilities. The benchmarks shall be confidential but shall be provided to, and will be subject to Commission review and approval, prior to a procurement event.
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(4) Request for proposals competitive procurement
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| process. The procurement administrator shall design and issue a request for proposals to supply electricity in accordance with each utility's procurement plan, as approved by the Commission. The request for proposals shall set forth a procedure for sealed, binding commitment bidding with pay-as-bid settlement, and provision for selection of bids on the basis of price.
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(5) A plan for implementing contingencies in the
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| event of supplier default or failure of the procurement process to fully meet the expected load requirement due to insufficient supplier participation, Commission rejection of results, or any other cause.
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(i) Event of supplier default: In the event of
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| supplier default, the utility shall review the contract of the defaulting supplier to determine if the amount of supply is 200 megawatts or greater, and if there are more than 60 days remaining of the contract term. If both of these conditions are met, and the default results in termination of the contract, the utility shall immediately notify the Illinois Power Agency that a request for proposals must be issued to procure replacement power, and the procurement administrator shall run an additional procurement event. If the contracted supply of the defaulting supplier is less than 200 megawatts or there are less than 60 days remaining of the contract term, the utility shall procure power and energy from the applicable regional transmission organization market, including ancillary services, capacity, and day-ahead or real time energy, or both, for the duration of the contract term to replace the contracted supply; provided, however, that if a needed product is not available through the regional transmission organization market it shall be purchased from the wholesale market.
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(ii) Failure of the procurement process to fully
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| meet the expected load requirement: If the procurement process fails to fully meet the expected load requirement due to insufficient supplier participation or due to a Commission rejection of the procurement results, the procurement administrator, the procurement monitor, and the Commission staff shall meet within 10 days to analyze potential causes of low supplier interest or causes for the Commission decision. If changes are identified that would likely result in increased supplier participation, or that would address concerns causing the Commission to reject the results of the prior procurement event, the procurement administrator may implement those changes and rerun the request for proposals process according to a schedule determined by those parties and consistent with Section 1-75 of the Illinois Power Agency Act and this subsection. In any event, a new request for proposals process shall be implemented by the procurement administrator within 90 days after the determination that the procurement process has failed to fully meet the expected load requirement.
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(iii) In all cases where there is insufficient
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| supply provided under contracts awarded through the procurement process to fully meet the electric utility's load requirement, the utility shall meet the load requirement by procuring power and energy from the applicable regional transmission organization market, including ancillary services, capacity, and day-ahead or real time energy, or both; provided, however, that if a needed product is not available through the regional transmission organization market it shall be purchased from the wholesale market.
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(6) The procurement processes described in this
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| subsection and in subsection (c-5) of Section 1-75 of the Illinois Power Agency Act are exempt from the requirements of the Illinois Procurement Code, pursuant to Section 20-10 of that Code.
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(f) Within 2 business days after opening the sealed bids, the procurement administrator shall submit a confidential report to the Commission. The report shall contain the results of the bidding for each of the products along with the procurement administrator's recommendation for the acceptance and rejection of bids based on the price benchmark criteria and other factors observed in the process. The procurement monitor also shall submit a confidential report to the Commission within 2 business days after opening the sealed bids. The report shall contain the procurement monitor's assessment of bidder behavior in the process as well as an assessment of the procurement administrator's compliance with the procurement process and rules. The Commission shall review the confidential reports submitted by the procurement administrator and procurement monitor, and shall accept or reject the recommendations of the procurement administrator within 2 business days after receipt of the reports.
(g) Within 3 business days after the Commission decision approving the results of a procurement event, the utility shall enter into binding contractual arrangements with the winning suppliers using the standard form contracts; except that the utility shall not be required either directly or indirectly to execute the contracts if a tariff that is consistent with subsection (l) of this Section has not been approved and placed into effect for that utility.
(h) For the procurement of standard wholesale products, the names of the successful bidders and the load weighted average of the winning bid prices for each contract type and for each contract term shall be made available to the public at the time of Commission approval of a procurement event. For procurements conducted to meet the requirements of subsection (b) of Section 1-56 or subsection (c) of Section 1-75 of the Illinois Power Agency Act governed by the provisions of this Section, the address and nameplate capacity of the new renewable energy generating facility proposed by a winning bidder shall also be made available to the public at the time of Commission approval of a procurement event, along with the business address and contact information for any winning bidder. An estimate or approximation of the nameplate capacity of the new renewable energy generating facility may be disclosed if necessary to protect the confidentiality of individual bid prices.
The Commission, the procurement monitor, the procurement administrator, the Illinois Power Agency, and all participants in the procurement process shall maintain the confidentiality of all other supplier and bidding information in a manner consistent with all applicable laws, rules, regulations, and tariffs. Confidential information, including the confidential reports submitted by the procurement administrator and procurement monitor pursuant to subsection (f) of this Section, shall not be made publicly available and shall not be discoverable by any party in any proceeding, absent a compelling demonstration of need, nor shall those reports be admissible in any proceeding other than one for law enforcement purposes.
(i) Within 2 business days after a Commission decision approving the results of a procurement event or such other date as may be required by the Commission from time to time, the utility shall file for informational purposes with the Commission its actual or estimated retail supply charges, as applicable, by customer supply group reflecting the costs associated with the procurement and computed in accordance with the tariffs filed pursuant to subsection (l) of this Section and approved by the Commission.
(j) Within 60 days following August 28, 2007 (the effective date of Public Act 95-481), each electric utility that on December 31, 2005 provided electric service to at least 100,000 customers in Illinois shall prepare and file with the Commission an initial procurement plan, which shall conform in all material respects to the requirements of the procurement plan set forth in subsection (b); provided, however, that the Illinois Power Agency Act shall not apply to the initial procurement plan prepared pursuant to this subsection. The initial procurement plan shall identify the portfolio of power and energy products to be procured and delivered for the period June 2008 through May 2009, and shall identify the proposed procurement administrator, who shall have the same experience and expertise as is required of a procurement administrator hired pursuant to Section 1-75 of the Illinois Power Agency Act. Copies of the procurement plan shall be posted and made publicly available on the Commission's website. The initial procurement plan may include contracts for renewable resources that extend beyond May 2009.
(i) Within 14 days following filing of the initial
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| procurement plan, any person may file a detailed objection with the Commission contesting the procurement plan submitted by the electric utility. All objections to the electric utility's plan shall be specific, supported by data or other detailed analyses. The electric utility may file a response to any objections to its procurement plan within 7 days after the date objections are due to be filed. Within 7 days after the date the utility's response is due, the Commission shall determine whether a hearing is necessary. If it determines that a hearing is necessary, it shall require the hearing to be completed and issue an order on the procurement plan within 60 days after the filing of the procurement plan by the electric utility.
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(ii) The order shall approve or modify the
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| procurement plan, approve an independent procurement administrator, and approve or modify the electric utility's tariffs that are proposed with the initial procurement plan. The Commission shall approve the procurement plan if the Commission determines that it will ensure adequate, reliable, affordable, efficient, and environmentally sustainable electric service at the lowest total cost over time, taking into account any benefits of price stability.
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(k) (Blank).
(k-5) (Blank).
(l) An electric utility shall recover its costs incurred under this Section and subsection (c-5) of Section 1-75 of the Illinois Power Agency Act, including, but not limited to, the costs of procuring power and energy demand-response resources under this Section and its costs for purchasing renewable energy credits pursuant to subsection (c-5) of Section 1-75 of the Illinois Power Agency Act. The utility shall file with the initial procurement plan its proposed tariffs through which its costs of procuring power that are incurred pursuant to a Commission-approved procurement plan and those other costs identified in this subsection (l), will be recovered. The tariffs shall include a formula rate or charge designed to pass through both the costs incurred by the utility in procuring a supply of electric power and energy for the applicable customer classes with no mark-up or return on the price paid by the utility for that supply, plus any just and reasonable costs that the utility incurs in arranging and providing for the supply of electric power and energy. The formula rate or charge shall also contain provisions that ensure that its application does not result in over or under recovery due to changes in customer usage and demand patterns, and that provide for the correction, on at least an annual basis, of any accounting errors that may occur. A utility shall recover through the tariff all reasonable costs incurred to implement or comply with any procurement plan that is developed and put into effect pursuant to Section 1-75 of the Illinois Power Agency Act and this Section, and for the procurement of renewable energy credits pursuant to subsection (c-5) of Section 1-75 of the Illinois Power Agency Act, including any fees assessed by the Illinois Power Agency, costs associated with load balancing, and contingency plan costs. The electric utility shall also recover its full costs of procuring electric supply for which it contracted before the effective date of this Section in conjunction with the provision of full requirements service under fixed-price bundled service tariffs subsequent to December 31, 2006. All such costs shall be deemed to have been prudently incurred. The pass-through tariffs that are filed and approved pursuant to this Section shall not be subject to review under, or in any way limited by, Section 16-111(i) of this Act. All of the costs incurred by the electric utility associated with the purchase of zero emission credits in accordance with subsection (d-5) of Section 1-75 of the Illinois Power Agency Act, all costs incurred by the electric utility associated with the purchase of carbon mitigation credits in accordance with subsection (d-10) of Section 1-75 of the Illinois Power Agency Act, and, beginning June 1, 2017, all of the costs incurred by the electric utility associated with the purchase of renewable energy resources in accordance with Sections 1-56 and 1-75 of the Illinois Power Agency Act, and all of the costs incurred by the electric utility in purchasing renewable energy credits in accordance with subsection (c-5) of Section 1-75 of the Illinois Power Agency Act, shall be recovered through the electric utility's tariffed charges applicable to all of its retail customers, as specified in subsection (k) or subsection (i-5), as applicable, of Section 16-108 of this Act, and shall not be recovered through the electric utility's tariffed charges for electric power and energy supply to its eligible retail customers.
(m) The Commission has the authority to adopt rules to carry out the provisions of this Section. For the public interest, safety, and welfare, the Commission also has authority to adopt rules to carry out the provisions of this Section on an emergency basis immediately following August 28, 2007 (the effective date of Public Act 95-481).
(n) Notwithstanding any other provision of this Act, any affiliated electric utilities that submit a single procurement plan covering their combined needs may procure for those combined needs in conjunction with that plan, and may enter jointly into power supply contracts, purchases, and other procurement arrangements, and allocate capacity and energy and cost responsibility therefor among themselves in proportion to their requirements.
(o) On or before June 1 of each year, the Commission shall hold an informal hearing for the purpose of receiving comments on the prior year's procurement process and any recommendations for change.
(p) An electric utility subject to this Section may propose to invest, lease, own, or operate an electric generation facility as part of its procurement plan, provided the utility demonstrates that such facility is the least-cost option to provide electric service to those retail customers included in the plan's electric supply service requirements. If the facility is shown to be the least-cost option and is included in a procurement plan prepared in accordance with Section 1-75 of the Illinois Power Agency Act and this Section, then the electric utility shall make a filing pursuant to Section 8-406 of this Act, and may request of the Commission any statutory relief required thereunder. If the Commission grants all of the necessary approvals for the proposed facility, such supply shall thereafter be considered as a pre-existing contract under subsection (b) of this Section. The Commission shall in any order approving a proposal under this subsection specify how the utility will recover the prudently incurred costs of investing in, leasing, owning, or operating such generation facility through just and reasonable rates charged to those retail customers included in the plan's electric supply service requirements. Cost recovery for facilities included in the utility's procurement plan pursuant to this subsection shall not be subject to review under or in any way limited by the provisions of Section 16-111(i) of this Act. Nothing in this Section is intended to prohibit a utility from filing for a fuel adjustment clause as is otherwise permitted under Section 9-220 of this Act.
(q) If the Illinois Power Agency filed with the Commission, under Section 16-111.5 of this Act, its proposed procurement plan for the period commencing June 1, 2017, and the Commission has not yet entered its final order approving the plan on or before the effective date of this amendatory Act of the 99th General Assembly, then the Illinois Power Agency shall file a notice of withdrawal with the Commission, after the effective date of this amendatory Act of the 99th General Assembly, to withdraw the proposed procurement of renewable energy resources to be approved under the plan, other than the procurement of renewable energy credits from distributed renewable energy generation devices using funds previously collected from electric utilities' retail customers that take service pursuant to electric utilities' hourly pricing tariff or tariffs and, for an electric utility that serves less than 100,000 retail customers in the State, other than the procurement of renewable energy credits from distributed renewable energy generation devices. Upon receipt of the notice, the Commission shall enter an order that approves the withdrawal of the proposed procurement of renewable energy resources from the plan. The initially proposed procurement of renewable energy resources shall not be approved or be the subject of any further hearing, investigation, proceeding, or order of any kind.
This amendatory Act of the 99th General Assembly preempts and supersedes any order entered by the Commission that approved the Illinois Power Agency's procurement plan for the period commencing June 1, 2017, to the extent it is inconsistent with the provisions of this amendatory Act of the 99th General Assembly. To the extent any previously entered order approved the procurement of renewable energy resources, the portion of that order approving the procurement shall be void, other than the procurement of renewable energy credits from distributed renewable energy generation devices using funds previously collected from electric utilities' retail customers that take service under electric utilities' hourly pricing tariff or tariffs and, for an electric utility that serves less than 100,000 retail customers in the State, other than the procurement of renewable energy credits for distributed renewable energy generation devices.
(Source: P.A. 102-662, eff. 9-15-21.)
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(220 ILCS 5/16-111.5A)
Sec. 16-111.5A. Provisions relating to electric rate relief.
(a) The General Assembly finds that action must be taken in order to mitigate the 2007 electric rate increases approved for residential and certain nonresidential customers served by the State's largest electric utilities in 2007. The General Assembly further finds that although various means of providing rate relief have been proposed, including imposition of a rate freeze on the electric utilities or a tax on generation within the State, the establishment of voluntary rate relief programs provides the most immediate and certain means of providing that rate relief. Accordingly, if the residential customer electric service rates that were charged to residential customers beginning January 2, 2007 by an electric utility that on December 31, 2005 provided electric service to at least 100,000 customers in Illinois resulted in an annual increase of more than 20% in an electric utility's average rate charged to residential customers for bundled electric service, those electric utilities and their holding companies or other affiliates, and any other company owning generation in this State or its affiliates, may, notwithstanding any other provisions of this Act, and without obtaining any approvals from the Commission or any other agency, regardless of whether any such approval would otherwise be required, establish and make payments to provide funds that can be used to provide rate relief beginning on the effective date of this amendatory Act of the 95th General Assembly through July 31, 2011. (b) For purposes of this Section, the "Ameren Utilities" means Illinois Power Company, Central Illinois Public Service Company, and Central Illinois Light Company. (c) For purposes of this Section, the "Generators" means Exelon Generation Company, LLC; Ameren Energy Resources Generating Company; Ameren Energy Marketing Company; Ameren Energy Generating Company; MidAmerican Energy Company; Midwest Generation, LLC; and Dynegy Holdings Inc.; and may include non-utility affiliates of the entities named in this subsection. (d) For purposes of this Section, "Rate Relief Agreements" means the 2 Rate Relief Funding Agreements, the Escrow Funding Agreement, and the Illinois Power Agency Funding Agreement that Commonwealth Edison Company, the Ameren Utilities, and Generators have entered into with the Illinois Attorney General on behalf of the People of the State of Illinois for the purpose of providing $1,001,000,000 to be used to fund rate relief programs for customers of Commonwealth Edison Company and the Ameren Utilities and for the Illinois Power Agency Trust Fund and that become effective on the effective date of this amendatory Act of the 95th General Assembly. The Rate Relief Agreements have been filed with the Illinois Secretary of State Index Department and designated as "95-GA-C01" through "95-GA-C04" inclusive. The Illinois Attorney General has the right to enforce the provisions of all of the Rate Relief Agreements on behalf of the People of the State of Illinois or the Illinois Power Agency, or both, as appropriate. (e) Subject to the terms, conditions, and contingencies of the Rate Relief Agreements, Commonwealth Edison Company will apply a total of $488,000,000 in rate relief to residential and certain nonresidential customers from 2007 through 2010. Commonwealth Edison Company will apply bill credits for all of its residential customers in its service territory in the following amounts: $250,000,000 in 2007, $125,500,000 in 2008, and $36,000,000 in 2009. Any undisbursed rate relief funds shall be applied to the targeted programs. Commonwealth Edison Company will provide rate relief for residential and certain nonresidential customers through targeted programs in the following amounts: $33,000,000 in 2007, $18,000,000 in 2008, $15,500,000 in 2009, and $10,000,000 in 2010. Subject to the terms, conditions, and contingencies of the Rate Relief Agreements, the targeted programs for 2007 consist of the following, some of which are already underway and, in the aggregate, therefore total more than $33,000,000: (1) an electric space heating customer relief program |
| costing approximately $8,000,000 designed to lower the average percentage increase of residential electric space heating customers to rate increases similar to other residential customers;
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(2) a summer assistance program costing approximately
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| $10,300,000 for working families and low-income customers, including low-income seniors;
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(3) a residential rate relief program costing
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| approximately $5,500,000 for working families and low-income customers, including low-income seniors, with higher than average rate increases (over 30%);
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(4) a residential special hardship program costing
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| approximately $5,000,000 to address special circumstances and hardships;
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(5) a nonresidential special hardship program costing
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| approximately $1,500,000 to address special circumstances and hardships;
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(6) a relief program for the common area accounts of
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| apartment building owners and condominium associations costing approximately $4,500,000 designed to reduce rate increases for these customers to rate increases similar to those for residential customers and to mitigate the impact of their rate increase;
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(7) a weatherization assistance program for electric
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| space heating low-income customers costing approximately $3,900,000 designed to provide energy efficiency assistance; and
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(8) energy efficiency, environmental, education, and
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| assistance programs costing approximately $5,000,000 designed to promote the use of energy efficiency programs and services by residential customers, maintenance and upgrades of a website that allows those customers to analyze their energy usage and provides incentives for the purchase of energy efficient products, the provision of energy efficient light bulbs to residential customers at a discount, and free efficient light bulbs and other assistance to low-income customers.
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Based on the outcome of these targeted programs, Commonwealth Edison Company will design and implement, subject to the terms, conditions, and contingencies of the Rate Relief Agreements, targeted programs for working families, seniors, and other customers in need in 2008, 2009, and 2010.
(f) Subject to the terms, conditions, and contingencies of the Rate Relief Agreements, the Ameren Utilities will apply a total of $488,000,000 in rate relief to residential and certain nonresidential customers from 2007 through 2010. The Ameren Utilities will apply bill credits for all of their residential customers in their service territories in the following aggregate amounts: $213,000,000 in 2007, $109,000,000 in 2008, and $78,000,000 in 2009. The Ameren Utilities will apply bill credits to certain nonresidential customers in the following aggregate amounts: $26,000,000 in 2007, $11,000,000 in 2008, and $11,000,000 in 2009. Any undisbursed rate relief funds shall be applied to the targeted programs. The Ameren Utilities will provide rate relief for residential and certain nonresidential customers through targeted programs in the following amounts: $13,500,000 in 2007, $13,500,000 in 2008, $7,500,000 in 2009, and $5,500,000 in 2010. Subject to the terms, conditions and contingencies of the Rate Relief Agreements, the targeted programs consist of the following for 2007:
(1) a cooling assistance program costing
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| approximately $2,000,000 to provide donations to the Low Income Home Energy Assistance Program;
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(2) a bill payment assistance program costing
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| approximately $2,000,000 for working families and low-income customers, including low-income seniors;
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(3) a residential special hardship program costing
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| approximately $2,000,000 to address special circumstances and hardships;
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(4) a nonresidential special hardship program costing
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| approximately $2,000,000 to address special circumstances and hardships;
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(5) a percent-of-income payment program pilot costing
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| approximately $2,500,000 that will be designed to determine for low-income electric space heating customers if paying a percentage of income for their electricity will make electricity more affordable and promote regular paying habits;
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(6) a weatherization assistance program for all
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| electric space heating low-income customers costing approximately $1,000,000 designed to provide energy efficiency assistance;
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(7) a compact fluorescent light bulb distribution
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| program costing approximately $1,000,000 designed to provide energy efficient light bulbs to residential customers at a discount; and
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(8) a municipal street lighting conversion program
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| costing approximately $1,000,000 to convert existing street lights to more efficient lights at a discount.
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Based on the outcome of these targeted programs, the Ameren Utilities will design and implement, subject to the terms, conditions, and contingencies of the Rate Relief Agreements, targeted programs for working families, seniors, and other customers in need in 2008, 2009, and 2010.
In addition, the Ameren Utilities voluntarily agree to waive outstanding late payment charges associated with unpaid electric bills for usage on and after January 2, 2007, through the September 2007 billing period.
(g) Programs that use funds that are provided by electric utilities and their holding companies or other affiliates, and any other company owning generation in this State or its affiliates, to reduce utility bills, or to otherwise offset costs incurred by the utilities in mitigating rate increases for certain customer groups, may be implemented through tariffs that are filed with and reviewed by the Commission. If a utility elects to file tariffs with the Commission to implement all or a portion of the programs, those tariffs shall, regardless of the date actually filed, be deemed accepted and approved, and shall become effective, on the effective date of this amendatory Act of the 95th General Assembly. The electric utilities whose customers benefit from the funds that are disbursed as contemplated in this Section shall file annual reports documenting the disbursement of those funds with the Commission and the Illinois Attorney General. The Commission has the authority to audit disbursement of the funds to ensure they were disbursed consistently with this Section.
(h) Nothing in this Section shall be interpreted to limit the Commission's general authority over ratemaking.
(i) Subject to the terms, conditions, and contingencies of the Rate Relief Agreements, the Generators are providing a total of $25,000,000 to the Illinois Power Agency Trust Fund.
(j) None of the contributions by Commonwealth Edison Company or the Ameren Utilities pursuant to this Section may be recovered in rates.
(k) Nothing in this Section shall be interpreted to limit the authority or right of the Illinois Attorney General, under the terms of the Rate Relief Agreements, to review or audit documents, make demands, or file suit or to take other action to enforce the provisions of the Rate Relief Agreements.
(Source: P.A. 95-481, eff. 8-28-07.)
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(220 ILCS 5/16-111.7) Sec. 16-111.7. On-bill financing program; electric utilities. (a) The Illinois General Assembly finds that Illinois homes and businesses have the potential to save energy through conservation and cost-effective energy efficiency measures. Programs created pursuant to this Section will allow utility customers to purchase cost-effective energy efficiency measures, including measures set forth in a Commission-approved energy efficiency and demand-response plan under Section 8-103 or 8-103B of this Act, with no required initial upfront payment, and to pay the cost of those products and services over time on their utility bill. (b) Notwithstanding any other provision of this Act, an electric utility serving more than 100,000 customers on January 1, 2009 shall offer a Commission-approved on-bill financing program ("program") that allows its eligible retail customers, as that term is defined in Section 16-111.5 of this Act, who own a residential single family home, duplex, or other residential building with 4 or less units, or condominium at which the electric service is being provided (i) to borrow funds from a third party lender in order to purchase electric energy efficiency measures approved under the program for installation in such home or condominium without any required upfront payment and (ii) to pay back such funds over time through the electric utility's bill. Based upon the process described in subsection (b-5) of this Section, small commercial customers who own the premises at which electric service is being provided may be included in such program. After receiving a request from an electric utility for approval of a proposed program and tariffs pursuant to this Section, the Commission shall render its decision within 120 days. If no decision is rendered within 120 days, then the request shall be deemed to be approved. Beginning no later than December 31, 2013, an electric utility subject to this subsection (b) shall also offer its program to eligible retail customers that own multifamily residential or mixed-use buildings with no more than 50 residential units, provided, however, that such customers must either be a residential customer or small commercial customer and may not use the program in such a way that repayment of the cost of energy efficiency measures is made through tenants' utility bills. An electric utility may impose a per site loan limit not to exceed $150,000. The program, and loans issued thereunder, shall only be offered to customers of the utility that meet the requirements of this Section and that also have an electric service account at the premises where the energy efficiency measures being financed shall be installed. Beginning no later than 2 years after the effective date of this amendatory Act of the 99th General Assembly, the 50 residential unit limitation described in this paragraph shall no longer apply, and the utility shall replace the per site loan limit of $150,000 with a loan limit that correlates to a maximum monthly payment that does not exceed 50% of the customer's average utility bill over the prior 12-month period. Beginning no later than 2 years after the effective date of this amendatory Act of the 99th General Assembly, an electric utility subject to this subsection (b) shall also offer its program to eligible retail customers that are Unit Owners' Associations, as defined in subsection (o) of Section 2 of the Condominium Property Act, or Master Associations, as defined in subsection (u) of the Condominium Property Act. However, such customers must either be residential customers or small commercial customers and may not use the program in such a way that repayment of the cost of energy efficiency measures is made through unit owners' utility bills. The program and loans issued under the program shall only be offered to customers of the utility that meet the requirements of this Section and that also have an electric service account at the premises where the energy efficiency measures being financed shall be installed. For purposes of this Section, "small commercial customer" means, for an electric utility serving more than 3,000,000 retail customers, those customers having peak demand of less than 100 kilowatts, and, for an electric utility serving less than 3,000,000 retail customers, those customers having peak demand of less than 150 kilowatts; provided, however, that in the event the Commission, after the effective date of this amendatory Act of the 98th General Assembly, approves changes to a utility's tariffs that reflects new or revised demand criteria for the utility's customer rate classifications, then the utility may file a petition with the Commission to revise the applicable definition of a small commercial customer to reflect the new or revised demand criteria for the purposes of this Section. After notice and hearing, the Commission shall enter an order approving, or approving with modification, the revised definition within 60 days after the utility files the petition. (b-5) Within 30 days after the effective date of this amendatory Act of the 96th General Assembly, the Commission shall convene a workshop process during which interested participants may discuss issues related to the program, including program design, eligible electric energy efficiency measures, vendor qualifications, and a methodology for ensuring ongoing compliance with such qualifications, financing, sample documents such as request for proposals, contracts and agreements, dispute resolution, pre-installment and post-installment verification, and evaluation. The workshop process shall be completed within 150 days after the effective date of this amendatory Act of the 96th General Assembly. (c) Not later than 60 days following completion of the workshop process described in subsection (b-5) of this Section, each electric utility subject to subsection (b) of this Section shall submit a proposed program to the Commission that contains the following components: (1) A list of recommended electric energy efficiency |
| measures that will be eligible for on-bill financing. An eligible electric energy efficiency measure ("measure") shall be a product or service for which one or more of the following is true:
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(A) (blank);
(B) the projected electricity savings (determined
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| by rates in effect at the time of purchase) are sufficient to cover the costs of implementing the measures, including finance charges and any program fees not recovered pursuant to subsection (f) of this Section; or
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(C) the product or service is included in a
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| Commission-approved energy efficiency and demand-response plan under Section 8-103 or 8-103B of this Act.
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(1.5) Beginning no later than 2 years after the
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| effective date of this amendatory Act of the 99th General Assembly, an eligible electric energy efficiency measure (measure) shall be a product or service that qualifies under subparagraph (B) or (C) of paragraph (1) of this subsection (c) or for which one or more of the following is true:
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(A) a building energy assessment, performed by an
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| energy auditor who is certified by the Building Performance Institute or who holds a similar certification, has recommended the product or service as likely to be cost effective over the course of its installed life for the building in which the measure is to be installed; or
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(B) the product or service is necessary to safely
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| or correctly install to code or industry standard an efficiency measure, including, but not limited to, installation work; changes needed to plumbing or electrical connections; upgrades to wiring or fixtures; removal of hazardous materials; correction of leaks; changes to thermostats, controls, or similar devices; and changes to venting or exhaust necessitated by the measure. However, the costs of the product or service described in this subparagraph (B) shall not exceed 25% of the total cost of installing the measure.
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(2) The electric utility shall issue a request for
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| proposals ("RFP") to lenders for purposes of providing financing to participants to pay for approved measures. The RFP criteria shall include, but not be limited to, the interest rate, origination fees, and credit terms. The utility shall select the winning bidders based on its evaluation of these criteria, with a preference for those bids containing the rates, fees, and terms most favorable to participants;
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(3) The utility shall work with the lenders selected
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| pursuant to the RFP process, and with vendors, to establish the terms and processes pursuant to which a participant can purchase eligible electric energy efficiency measures using the financing obtained from the lender. The vendor shall explain and offer the approved financing packaging to those customers identified in subsection (b) of this Section and shall assist customers in applying for financing. As part of the process, vendors shall also provide to participants information about any other incentives that may be available for the measures.
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(4) The lender shall conduct credit checks or
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| undertake other appropriate measures to limit credit risk, and shall review and approve or deny financing applications submitted by customers identified in subsection (b) of this Section. Following the lender's approval of financing and the participant's purchase of the measure or measures, the lender shall forward payment information to the electric utility, and the utility shall add as a separate line item on the participant's utility bill a charge showing the amount due under the program each month.
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(5) A loan issued to a participant pursuant to the
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| program shall be the sole responsibility of the participant, and any dispute that may arise concerning the loan's terms, conditions, or charges shall be resolved between the participant and lender. Upon transfer of the property title for the premises at which the participant receives electric service from the utility or the participant's request to terminate service at such premises, the participant shall pay in full its electric utility bill, including all amounts due under the program, provided that this obligation may be modified as provided in subsection (g) of this Section. Amounts due under the program shall be deemed amounts owed for residential and, as appropriate, small commercial electric service.
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(6) The electric utility shall remit payment in full
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| to the lender each month on behalf of the participant. In the event a participant defaults on payment of its electric utility bill, the electric utility shall continue to remit all payments due under the program to the lender, and the utility shall be entitled to recover all costs related to a participant's nonpayment through the automatic adjustment clause tariff established pursuant to Section 16-111.8 of this Act. In addition, the electric utility shall retain a security interest in the measure or measures purchased under the program, and the utility retains its right to disconnect a participant that defaults on the payment of its utility bill.
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(7) The total outstanding amount financed under the
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| program in this subsection and subsection (c-5) of this Section shall not exceed $2.5 million for an electric utility or electric utilities under a single holding company, provided that the electric utility or electric utilities may petition the Commission for an increase in such amount. Beginning after the effective date of this amendatory Act of the 99th General Assembly, the total maximum outstanding amount financed under the program in this subsection and subsections (c-5) and (c-10) of this Section shall increase by $5,000,000 per year until such time as the total maximum outstanding amount financed reaches $20,000,000. For purposes of this Section, "maximum outstanding amount financed" means the sum of all principal that has been loaned and not yet repaid.
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(c-5) Within 120 days after the effective date of this amendatory Act of the 98th General Assembly, each electric utility subject to the requirements of this Section shall submit an informational filing to the Commission that describes its plan for implementing the provisions of this amendatory Act of the 98th General Assembly on or before December 31, 2013. Such filing shall also describe how the electric utility shall coordinate its program with any gas utility or utilities that provide gas service to buildings within the electric utility's service territory so that it is practical and feasible for the owner of a multifamily building to make a single application to access loans for both gas and electric energy efficiency measures in any individual building.
(c-10) No later than 365 days after the effective date of this amendatory Act of the 99th General Assembly, each electric utility subject to the requirements of this Section shall submit an informational filing to the Commission that describes its plan for implementing the provisions of this amendatory Act of the 99th General Assembly that were incorporated into this Section. Such filing shall also include the criteria to be used by the program for determining if measures to be financed are eligible electric energy efficiency measures, as defined by paragraph (1.5) of subsection (c) of this Section.
(d) A program approved by the Commission shall also include the following criteria and guidelines for such program:
(1) guidelines for financing of measures installed
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| under a program, including, but not limited to, RFP criteria and limits on both individual loan amounts and the duration of the loans;
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(2) criteria and standards for identifying and
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(3) qualifications of vendors that will market or
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| install measures, as well as a methodology for ensuring ongoing compliance with such qualifications;
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(4) sample contracts and agreements necessary to
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| implement the measures and program; and
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(5) the types of data and information that utilities
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| and vendors participating in the program shall collect for purposes of preparing the reports required under subsection (g) of this Section.
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(e) The proposed program submitted by each electric utility shall be consistent with the provisions of this Section that define operational, financial and billing arrangements between and among program participants, vendors, lenders, and the electric utility.
(f) An electric utility shall recover all of the prudently incurred costs of offering a program approved by the Commission pursuant to this Section, including, but not limited to, all start-up and administrative costs and the costs for program evaluation. All prudently incurred costs under this Section shall be recovered from the residential and small commercial retail customer classes eligible to participate in the program through the automatic adjustment clause tariff established pursuant to Section 8-103 or 8-103B of this Act.
(g) An independent evaluation of a program shall be conducted after 3 years of the program's operation. The electric utility shall retain an independent evaluator who shall evaluate the effects of the measures installed under the program and the overall operation of the program, including, but not limited to, customer eligibility criteria and whether the payment obligation for permanent electric energy efficiency measures that will continue to provide benefits of energy savings should attach to the meter location. As part of the evaluation process, the evaluator shall also solicit feedback from participants and interested stakeholders. The evaluator shall issue a report to the Commission on its findings no later than 4 years after the date on which the program commenced, and the Commission shall issue a report to the Governor and General Assembly including a summary of the information described in this Section as well as its recommendations as to whether the program should be discontinued, continued with modification or modifications or continued without modification, provided that any recommended modifications shall only apply prospectively and to measures not yet installed or financed.
(h) An electric utility offering a Commission-approved program pursuant to this Section shall not be required to comply with any other statute, order, rule, or regulation of this State that may relate to the offering of such program, provided that nothing in this Section is intended to limit the electric utility's obligation to comply with this Act and the Commission's orders, rules, and regulations, including Part 280 of Title 83 of the Illinois Administrative Code.
(i) The source of a utility customer's electric supply shall not disqualify a customer from participation in the utility's on-bill financing program. Customers of alternative retail electric suppliers may participate in the program under the same terms and conditions applicable to the utility's supply customers.
(Source: P.A. 98-586, eff. 8-27-13; 99-906, eff. 6-1-17 .)
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(220 ILCS 5/16-115)
Sec. 16-115. Certification of alternative retail
electric suppliers. (a) Any alternative retail electric supplier must obtain
a certificate of service authority from the Commission in
accordance with this Section before serving any retail
customer or other user located in this State. An alternative
retail electric supplier may request, and the Commission may
grant, a certificate of service authority for the entire State
or for a specified geographic area of the State. A certificate granted pursuant to this Section is not property, and the grant of a certificate to an entity does not create a property interest in the certificate. This Section does not diminish the existing rights of a certificate holder to notice and hearing as proscribed by the Illinois Administrative Procedure Act and in rules adopted by the Commission.
(b) An alternative retail electric supplier seeking a
certificate of service authority shall file with the
Commission a verified application containing information
showing that the applicant meets the requirements of this
Section. The alternative retail electric supplier shall
publish notice of its application in the official State
newspaper within 10 days following the date of its filing. No
later than 45 days after a complete application is properly filed
with the Commission, and such notice is published, the
Commission shall issue its order granting or denying the
application.
(c) An application for a certificate of service
authority shall identify the area or areas in which the
applicant intends to offer service and the types of services
it intends to offer. Applicants that seek to serve
residential or small commercial retail customers within a
geographic area that is smaller than an electric utility's
service area shall submit evidence demonstrating that the
designation of this smaller area does not violate Section 16-115A. An applicant
that seeks to serve residential or small
commercial retail customers may state in its application for
certification any limitations that will be imposed on the
number of customers or maximum load to be served.
(d) The Commission shall grant the application for a
certificate of service authority if it makes the findings set
forth in this subsection
based on the verified
application and such other information as the applicant may
submit:
(1) That the applicant possesses sufficient |
| technical, financial, and managerial resources and abilities to provide the service for which it seeks a certificate of service authority. In determining the level of technical, financial, and managerial resources and abilities which the applicant must demonstrate, the Commission shall consider (i) the characteristics, including the size and financial sophistication, of the customers that the applicant seeks to serve, and (ii) whether the applicant seeks to provide electric power and energy using property, plant, and equipment which it owns, controls, or operates;
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(2) That the applicant will comply with all
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| applicable federal, State, regional, and industry rules, policies, practices, and procedures for the use, operation, and maintenance of the safety, integrity, and reliability, of the interconnected electric transmission system;
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(3) That the applicant will only provide service to
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| retail customers in an electric utility's service area that are eligible to take delivery services under this Act;
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(4) That the applicant will comply with such
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| informational or reporting requirements as the Commission may by rule establish and provide the information required by Section 16-112. Any data related to contracts for the purchase and sale of electric power and energy shall be made available for review by the Staff of the Commission on a confidential and proprietary basis and only to the extent and for the purposes which the Commission determines are reasonably necessary in order to carry out the purposes of this Act;
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(5) That the applicant will procure renewable energy
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| resources in accordance with Section 16-115D of this Act, and will source electricity from clean coal facilities, as defined in Section 1-10 of the Illinois Power Agency Act, in amounts at least equal to the percentages set forth in subsections (c) and (d) of Section 1-75 of the Illinois Power Agency Act. For purposes of this Section:
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(i) (blank);
(ii) (blank);
(iii) the required sourcing of electricity
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| generated by clean coal facilities, other than the initial clean coal facility, shall be limited to the amount of electricity that can be procured or sourced at a price at or below the benchmarks approved by the Commission each year in accordance with item (1) of subsection (c) and items (1) and (5) of subsection (d) of Section 1-75 of the Illinois Power Agency Act;
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(iv) all alternative retail electric suppliers
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| shall execute a sourcing agreement to source electricity from the initial clean coal facility, on the terms set forth in paragraphs (3) and (4) of subsection (d) of Section 1-75 of the Illinois Power Agency Act, except that in lieu of the requirements in subparagraphs (A)(v), (B)(i), (C)(v), and (C)(vi) of paragraph (3) of that subsection (d), the applicant shall execute one or more of the following:
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(1) if the sourcing agreement is a power
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| purchase agreement, a contract with the initial clean coal facility to purchase in each hour an amount of electricity equal to all clean coal energy made available from the initial clean coal facility during such hour, which the utilities are not required to procure under the terms of subsection (d) of Section 1-75 of the Illinois Power Agency Act, multiplied by a fraction, the numerator of which is the alternative retail electric supplier's retail market sales of electricity (expressed in kilowatthours sold) in the State during the prior calendar month and the denominator of which is the total sales of electricity (expressed in kilowatthours sold) in the State by alternative retail electric suppliers during such prior month that are subject to the requirements of this paragraph (5) of subsection (d) of this Section and subsection (d) of Section 1-75 of the Illinois Power Agency Act plus the total sales of electricity (expressed in kilowatthours sold) by utilities outside of their service areas during such prior month, pursuant to subsection (c) of Section 16-116 of this Act; or
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(2) if the sourcing agreement is a contract
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| for differences, a contract with the initial clean coal facility in each hour with respect to an amount of electricity equal to all clean coal energy made available from the initial clean coal facility during such hour, which the utilities are not required to procure under the terms of subsection (d) of Section 1-75 of the Illinois Power Agency Act, multiplied by a fraction, the numerator of which is the alternative retail electric supplier's retail market sales of electricity (expressed in kilowatthours sold) in the State during the prior calendar month and the denominator of which is the total sales of electricity (expressed in kilowatthours sold) in the State by alternative retail electric suppliers during such prior month that are subject to the requirements of this paragraph (5) of subsection (d) of this Section and subsection (d) of Section 1-75 of the Illinois Power Agency Act plus the total sales of electricity (expressed in kilowatthours sold) by utilities outside of their service areas during such prior month, pursuant to subsection (c) of Section 16-116 of this Act;
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(v) if, in any year after the first year of
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| commercial operation, the owner of the clean coal facility fails to demonstrate to the Commission that the initial clean coal facility captured and sequestered at least 50% of the total carbon emissions that the facility would otherwise emit or that sequestration of emissions from prior years has failed, resulting in the release of carbon into the atmosphere, the owner of the facility must offset excess emissions. Any such carbon offsets must be permanent, additional, verifiable, real, located within the State of Illinois, and legally and practicably enforceable. The costs of any such offsets that are not recoverable shall not exceed $15,000,000 in any given year. No costs of any such purchases of carbon offsets may be recovered from an alternative retail electric supplier or its customers. All carbon offsets purchased for this purpose and any carbon emission credits associated with sequestration of carbon from the facility must be permanently retired. The initial clean coal facility shall not forfeit its designation as a clean coal facility if the facility fails to fully comply with the applicable carbon sequestration requirements in any given year, provided the requisite offsets are purchased. However, the Attorney General, on behalf of the People of the State of Illinois, may specifically enforce the facility's sequestration requirement and the other terms of this contract provision. Compliance with the sequestration requirements and offset purchase requirements that apply to the initial clean coal facility shall be reviewed annually by an independent expert retained by the owner of the initial clean coal facility, with the advance written approval of the Attorney General;
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(vi) The Commission shall, after notice and
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| hearing, revoke the certification of any alternative retail electric supplier that fails to execute a sourcing agreement with the initial clean coal facility as required by item (5) of subsection (d) of this Section. The sourcing agreements with this initial clean coal facility shall be subject to both approval of the initial clean coal facility by the General Assembly and satisfaction of the requirements of item (4) of subsection (d) of Section 1-75 of the Illinois Power Agency Act, and shall be executed within 90 days after any such approval by the General Assembly. The Commission shall not accept an application for certification from an alternative retail electric supplier that has lost certification under this subsection (d), or any corporate affiliate thereof, for at least one year from the date of revocation;
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(6) With respect to an applicant that seeks to serve
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| residential or small commercial retail customers, that the area to be served by the applicant and any limitations it proposes on the number of customers or maximum amount of load to be served meet the provisions of Section 16-115A, provided, that the Commission can extend the time for considering such a certificate request by up to 90 days, and can schedule hearings on such a request;
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(7) That the applicant meets the requirements of
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| subsection (a) of Section 16-128;
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(8) That the applicant discloses whether the
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| applicant is the subject of any lawsuit filed in a court of law or formal complaint filed with a regulatory agency alleging fraud, deception, or unfair marketing practices or other similar allegations and, if the applicant is the subject of such lawsuit or formal complaint, the applicant shall identify the name, case number, and jurisdiction of each lawsuit or complaint, and that the applicant is capable of fulfilling its obligations as an alternative retail electric supplier in Illinois notwithstanding any lawsuit or complaint. For the purpose of this item (8), "formal complaint" includes only those complaints that seek a binding determination from a State or federal regulatory body;
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(9) That the applicant shall at all times remain in
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| compliance with requirements for certification stated in this Section and as the Commission may establish by rule;
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(10) That the applicant shall execute and maintain a
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| license or permit bond issued by a qualifying surety or insurance company authorized to transact business in the State of Illinois in favor of the People of the State of Illinois. The amount of the bond shall equal $30,000 if the applicant seeks to serve only nonresidential retail customers with maximum electrical demands of one megawatt or more, $150,000 if the applicant seeks to serve only nonresidential retail customers with annual electrical consumption greater than 15,000 kilowatt-hours, or $500,000 if the applicant seeks to serve all eligible customers. Applicants shall be required to submit an additional $500,000 bond if the applicant intends to market to residential customers using in-person solicitations. The bonds shall be conditioned upon the full and faithful performance of all duties and obligations of the applicant as an alternative retail electric supplier, shall be valid for a period of not less than one year, and may be drawn upon in whole or in part to satisfy any penalties imposed, and finally adjudicated, by the Commission pursuant to Section 16-115B for a violation of the applicant's duties or obligations, except that the total amount of claims and penalties against the bond shall not exceed the penal sum of the bond and shall not include any consequential or punitive damage. The cost of the bond shall be paid by the applicant. The applicant shall file a copy of this bond, with a notarized verification page from the issuer, as part of its application for certification under 83 Ill. Adm. Code 451; and
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(11) That the applicant will comply with all other
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| applicable laws and regulations.
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(d-3) The Commission may deny with prejudice an application in which the applicant fails to provide the Commission with information sufficient for the Commission to grant the application.
(d-5) (Blank).
(e) A retail customer that owns a cogeneration or self-generation facility
and that seeks certification only to
provide electric power and energy from such facility to
retail customers at separate locations which customers are
both (i) owned by, or a subsidiary or other corporate
affiliate of, such applicant and
(ii) eligible for delivery services, shall be granted a
certificate of service authority upon filing an application
and notifying the Commission that it has entered into an
agreement with the relevant electric utilities pursuant to
Section 16-118.
Provided, however, that if the retail customer owning such cogeneration or
self-generation facility would not be charged a transition charge due to the
exemption provided under subsection (f) of Section 16-108 prior to the
certification, and the retail customers at separate locations are taking
delivery services in conjunction with purchasing power and energy from the
facility, the retail customer on whose premises the facility is located shall
not thereafter be required to pay transition charges on the power and energy
that such retail customer takes from the facility.
(f) The Commission shall have the authority to
promulgate rules and regulations to carry out the provisions
of this Section. On or before May 1, 1999, the Commission
shall adopt a rule or rules applicable to the certification of
those alternative retail electric suppliers that seek to serve
only nonresidential retail customers with maximum electrical
demands of one megawatt or more which shall provide for (i)
expedited and streamlined procedures
for certification of such alternative
retail electric suppliers and (ii) specific criteria which,
if met by any such alternative retail electric supplier, shall
constitute the demonstration of technical, financial and
managerial resources and abilities to provide service required
by paragraph (1) of subsection (d) of this Section, such as a requirement
to post a bond or letter of credit, from a responsible surety
or financial institution, of sufficient size for the nature
and scope of the services to be provided; demonstration of
adequate insurance for the scope and nature of the services to
be provided; and experience in providing similar services in
other jurisdictions.
(g) An alternative retail electric supplier may seek confidential treatment for the following information by filing an affidavit with the Commission so long as the affidavit meets the requirements in this subsection (g):
(1) the total annual kilowatt-hours delivered and
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| sold by an alternative retail electric supplier to retail customers within each utility service territory and the total annual kilowatt-hours delivered and sold by an alternative retail electric supplier to retail customers in all utility service territories in the preceding calendar year as required by 83 Ill. Adm. Code 451.770;
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(2) the total peak demand supplied by an alternative
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| retail electric supplier during the previous year in each utility service territory as required by 83 Ill. Adm. Code 465.40;
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(3) a good faith estimate of the amount an
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| alternative retail electric supplier expects to be obliged to pay the utility under single billing tariffs during the next 12 months and the amount of any bond or letter of credit used to demonstrate an alternative retail electric supplier's credit worthiness to provide single billing services pursuant to 83 Ill. Adm. Code 451.510(a) and (b).
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The affidavit must be filed contemporaneously with the information for which confidential treatment is sought and must clearly state that the affiant seeks confidential treatment pursuant to this subsection (g) and the information for which confidential treatment is sought must be clearly identified on the confidential version of the document filed with the Commission. The affidavit must be accompanied by a "confidential" and a "public" version of the document or documents containing the information for which confidential treatment is sought.
If the alternative retail electric supplier has met the affidavit requirements of this subsection (g), then the Commission shall afford confidential treatment to the information identified in the affidavit for a period of 2 years after the date the affidavit is received by the Commission.
Nothing in this subsection (g) prevents an alternative retail electric supplier from filing a petition with the Commission seeking confidential treatment for information beyond that identified in this subsection (g) or for information contained in other reports or documents filed with the Commission other than annual rate reports.
Nothing in this subsection (g) prevents the Commission, on its own motion, or any party from filing a formal petition with the Commission seeking to reconsider the conferring of confidential status on an item of information afforded confidential treatment pursuant to this subsection (g).
The Commission, on its own motion, may at any time initiate a docketed proceeding to investigate the continued applicability of this subsection (g) to the information contained in items (i), (ii), and (iii) of this subsection (g). If, at the end of such investigation, the Commission determines that a particular item of information should no longer be eligible for the affidavit-based process outlined in this subsection (g), the Commission may enter an order to remove that item from the list of items eligible for the process set forth in this subsection (g). Notwithstanding any such order, in the event the Commission makes such a determination, nothing in this subsection (g) prevents an alternative retail electric supplier desiring confidential treatment for such information from filing a formal petition with the Commission seeking confidential treatment for such information.
(Source: P.A. 101-590, eff. 1-1-20; 102-958, eff. 1-1-23 .)
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(220 ILCS 5/16-115A)
Sec. 16-115A. Obligations of alternative retail electric
suppliers. (a) An alternative retail electric supplier:
(i) shall comply with the requirements imposed on |
| public utilities by Sections 8-201 through 8-207, 8-301, 8-505 and 8-507 of this Act, to the extent that these Sections have application to the services being offered by the alternative retail electric supplier;
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(ii) shall continue to comply with the requirements
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| for certification stated in subsection (d) of Section 16-115;
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(iii) by May 31, 2020 and every June 30 thereafter,
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| shall submit to the Commission and the Office of the Attorney General the rates the retail electric supplier charged to residential customers in the prior year, including each distinct rate charged and whether the rate was a fixed or variable rate, the basis for the variable rate, and any fees charged in addition to the supply rate, including monthly fees, flat fees, or other service charges; and
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(iv) shall make publicly available on its website,
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| without the need for a customer login, rate information for all of its variable, time-of-use, and fixed rate contracts currently available to residential customers, including, but not limited to, fixed monthly charges, early termination fees, and kilowatt-hour charges.
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(b) An alternative retail electric supplier shall obtain verifiable
authorization from a customer, in a form or manner approved by the Commission
consistent with Section 2EE of the Consumer Fraud and Deceptive Business
Practices Act, before the customer is switched from another supplier.
(c) No alternative retail electric supplier, or electric
utility other than the electric utility in whose service area
a customer is located, shall (i) enter into or employ any
arrangements which have the effect of preventing a retail
customer with a maximum electrical demand of less than one
megawatt from having access to the services of the electric
utility in whose service area the customer is located or (ii)
charge retail customers for such access. This subsection shall not be
construed to prevent an arms-length agreement between a
supplier and a retail customer that sets a term of service, notice
period for terminating service and provisions governing early
termination through a tariff or contract as allowed by Section 16-119.
(d) An alternative retail electric supplier that is
certified to serve residential or small commercial retail
customers shall not:
(1) deny service to a customer or group of customers
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| nor establish any differences as to prices, terms, conditions, services, products, facilities, or in any other respect, whereby such denial or differences are based upon race, gender or income, except as provided in Section 16-115E.
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(2) deny service to a customer or group of customers
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| based on locality nor establish any unreasonable difference as to prices, terms, conditions, services, products, or facilities as between localities.
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(3) warrant that it has a residential customer or
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| small commercial retail customer's express consent agreement to access interval data as described in subsection (b) of Section 16-122, unless the alternative retail electric supplier has:
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(A) disclosed to the consumer at the outset of
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| the offer that the alternative retail electric supplier will access the consumer's interval data from the consumer's utility with the consumer's express agreement and the consumer's option to refuse to provide express agreement to access the consumer's interval data; and
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(B) obtained the consumer's express agreement for
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| the alternative retail electric supplier to access the consumer's interval data from the consumer's utility in a separate letter of agency, a distinct response to a third-party verification, or as a separate affirmative consent during a recorded enrollment initiated by the consumer. The disclosure by the alternative retail electric supplier to the consumer in this Section shall be conducted in, translated into, and provided in a language in which the consumer subject to the disclosure is able to understand and communicate.
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(4) release, sell, license, or otherwise disclose
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| any customer interval data obtained under Section 16-122 to any third person except as provided for in Section 16-122 and paragraphs (1) through (4) of subsection (d-5) of Section 2EE of the Consumer Fraud and Deceptive Business Practices Act.
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(e) An alternative retail electric supplier shall comply
with the following requirements with respect to the marketing,
offering and provision of products or services to residential
and small commercial retail customers:
(i) All marketing materials, including, but not
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| limited to, electronic marketing materials, in-person solicitations, and telephone solicitations, shall contain information that adequately discloses the prices, terms, and conditions of the products or services that the alternative retail electric supplier is offering or selling to the customer and shall disclose the current utility electric supply price to compare applicable at the time the alternative retail electric supplier is offering or selling the products or services to the customer and shall disclose the date on which the utility electric supply price to compare became effective and the date on which it will expire. The utility electric supply price to compare shall be the sum of the electric supply charge and the transmission services charge and shall not include the purchased electricity adjustment. The disclosure shall include a statement that the price to compare does not include the purchased electricity adjustment, and, if applicable, the range of the purchased electricity adjustment. All marketing materials, including, but not limited to, electronic marketing materials, in-person solicitations, and telephone solicitations, shall include the following statement:
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"(Name of the alternative retail electric
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| supplier) is not the same entity as your electric delivery company. You are not required to enroll with (name of alternative retail electric supplier). Beginning on (effective date), the electric supply price to compare is (price in cents per kilowatt hour). The electric utility electric supply price will expire on (expiration date). The utility electric supply price to compare does not include the purchased electricity adjustment factor. For more information go to the Illinois Commerce Commission's free website at www.pluginillinois.org.".
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If applicable, the statement shall also include the
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"The purchased electricity adjustment factor may
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| range between +.5 cents and -.5 cents per kilowatt hour.".
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This paragraph (i) does not apply to goodwill or
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| institutional advertising.
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(ii) Before any customer is switched from another
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| supplier, the alternative retail electric supplier shall give the customer written information that adequately discloses, in plain language, the prices, terms and conditions of the products and services being offered and sold to the customer. This written information shall be provided in a language in which the customer subject to the marketing or solicitation is able to understand and communicate, and the alternative retail electric supplier shall not switch a customer who is unable to understand and communicate in a language in which the marketing or solicitation was conducted. The alternative retail electric supplier shall comply with Section 2N of the Consumer Fraud and Deceptive Business Practices Act.
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(iii) An alternative retail electric supplier shall
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| provide documentation to the Commission and to customers that substantiates any claims made by the alternative retail electric supplier regarding the technologies and fuel types used to generate the electricity offered or sold to customers.
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(iv) The alternative retail electric supplier shall
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| provide to the customer (1) itemized billing statements that describe the products and services provided to the customer and their prices, and (2) an additional statement, at least annually, that adequately discloses the average monthly prices, and the terms and conditions, of the products and services sold to the customer.
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(v) All in-person and telephone solicitations shall
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| be conducted in, translated into, and provided in a language in which the consumer subject to the marketing or solicitation is able to understand and communicate. An alternative retail electric supplier shall terminate a solicitation if the consumer subject to the marketing or communication is unable to understand and communicate in the language in which the marketing or solicitation is being conducted. An alternative retail electric supplier shall comply with Section 2N of the Consumer Fraud and Deceptive Business Practices Act.
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(vi) Each alternative retail electric supplier shall
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| conduct training for individual representatives engaged in in-person solicitation and telemarketing to residential customers on behalf of that alternative retail electric supplier prior to conducting any such solicitations on the alternative retail electric supplier's behalf. Each alternative retail electric supplier shall submit a copy of its training material to the Commission on an annual basis and the Commission shall have the right to review and require updates to the material. After initial training, each alternative retail electric supplier shall be required to conduct refresher training for its individual representatives every 6 months.
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(f) An alternative retail electric supplier may limit
the overall size or availability of a service offering by
specifying one or more of the following: a maximum number of
customers, maximum amount of electric load to be served, time
period during which the offering will be available, or other
comparable limitation, but not including the geographic
locations of customers within the area which the alternative
retail electric supplier is certificated to serve. The
alternative retail electric supplier shall file the terms and
conditions of such service offering including the applicable
limitations with the Commission prior to making the service
offering available to customers.
(g) Nothing in this Section shall be construed as
preventing an alternative retail electric supplier,
which is an affiliate of, or which contracts with, (i) an
industry or trade organization or association, (ii) a
membership organization or association that exists for a
purpose other than the purchase of electricity, or (iii)
another organization that meets criteria established in a rule
adopted by the Commission, from offering through the
organization or association services at prices, terms and
conditions that are available solely to the members of the
organization or association.
(Source: P.A. 102-459, eff. 8-20-21; 103-237, eff. 6-30-23.)
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(220 ILCS 5/16-115D) Sec. 16-115D. Renewable portfolio standard for alternative retail electric suppliers and electric utilities operating outside their service territories. (a) An alternative retail electric supplier shall be responsible for procuring cost-effective renewable energy resources as required under item (5) of subsection (d) of Section 16-115 of this Act as outlined herein: (1) The definition of renewable energy resources |
| contained in Section 1-10 of the Illinois Power Agency Act applies to all renewable energy resources required to be procured by alternative retail electric suppliers.
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(2) Through May 31, 2017, the quantity of renewable
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| energy resources shall be measured as a percentage of the actual amount of metered electricity (megawatt-hours) delivered by the alternative retail electric supplier to Illinois retail customers during the 12-month period June 1 through May 31, commencing June 1, 2009, and the comparable 12-month period in each year thereafter except as provided in item (6) of this subsection (a).
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(3) Through May 31, 2017, the quantity of renewable
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| energy resources shall be in amounts at least equal to the annual percentages set forth in item (1) of subsection (c) of Section 1-75 of the Illinois Power Agency Act. At least 60% of the renewable energy resources procured pursuant to items (1) and (3) of subsection (b) of this Section shall come from wind generation and, starting June 1, 2015, at least 6% of the renewable energy resources procured pursuant to items (1) and (3) of subsection (b) of this Section shall come from solar photovoltaics. If, in any given year, an alternative retail electric supplier does not purchase at least these levels of renewable energy resources, then the alternative retail electric supplier shall make alternative compliance payments, as described in subsection (d) of this Section.
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(3.5) For the delivery year commencing June 1,
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| 2017, the quantity of renewable energy resources shall be at least 13.0% of the uncovered amount of metered electricity (megawatt-hours) delivered by the alternative retail electric supplier to Illinois retail customers during the delivery year, which uncovered amount shall equal 50% of such metered electricity delivered by the alternative retail electric supplier. For the delivery year commencing June 1, 2018, the quantity of renewable energy resources shall be at least 14.5% of the uncovered amount of metered electricity (megawatt-hours) delivered by the alternative retail electric supplier to Illinois retail customers during the delivery year, which uncovered amount shall equal 25% of such metered electricity delivered by the alternative retail electric supplier. At least 32% of the renewable energy resources procured by the alternative retail electric supplier for its uncovered portion under this paragraph (3.5) shall come from wind or photovoltaic generation. The renewable energy resources procured under this paragraph (3.5) shall not include any resources from a facility whose costs were being recovered through rates regulated by any state or states on or after January 1, 2017.
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(4) The quantity and source of renewable energy
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| resources shall be independently verified through the PJM Environmental Information System Generation Attribute Tracking System (PJM-GATS) or the Midwest Renewable Energy Tracking System (M-RETS), which shall document the location of generation, resource type, month, and year of generation for all qualifying renewable energy resources that an alternative retail electric supplier uses to comply with this Section. No later than June 1, 2009, the Illinois Power Agency shall provide PJM-GATS, M-RETS, and alternative retail electric suppliers with all information necessary to identify resources located in Illinois, within states that adjoin Illinois or within portions of the PJM and MISO footprint in the United States that qualify under the definition of renewable energy resources in Section 1-10 of the Illinois Power Agency Act for compliance with this Section 16-115D. Alternative retail electric suppliers shall not be subject to the requirements in item (3) of subsection (c) of Section 1-75 of the Illinois Power Agency Act.
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(5) All renewable energy credits used to comply with
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| this Section shall be permanently retired.
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(6) The required procurement of renewable energy
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| resources by an alternative retail electric supplier shall apply to all metered electricity delivered to Illinois retail customers by the alternative retail electric supplier pursuant to contracts executed or extended after March 15, 2009.
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(b) Compliance obligations.
(1) Through May 31, 2017, an alternative retail
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| electric supplier shall comply with the renewable energy portfolio standards by making an alternative compliance payment, as described in subsection (d) of this Section, to cover at least one-half of the alternative retail electric supplier's compliance obligation for the period prior to June 1, 2017.
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(2) For the delivery years beginning June 1, 2017 and
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| June 1, 2018, an alternative retail electric supplier need not make any alternative compliance payment to meet any portion of its compliance obligation, as set forth in paragraph (3.5) of subsection (a) of this Section.
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(3) An alternative retail electric supplier shall
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| use any one or combination of the following means to cover the remainder of the alternative retail electric supplier's compliance obligation, as set forth in paragraphs (3) and (3.5) of subsection (a) of this Section, not covered by an alternative compliance payment made under paragraphs (1) and (2) of this subsection (b) of this Section:
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(A) Generating electricity using renewable energy
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| resources identified pursuant to item (4) of subsection (a) of this Section.
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(B) Purchasing electricity generated using
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| renewable energy resources identified pursuant to item (4) of subsection (a) of this Section through an energy contract.
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(C) Purchasing renewable energy credits from
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| renewable energy resources identified pursuant to item (4) of subsection (a) of this Section.
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(D) Making an alternative compliance payment as
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| described in subsection (d) of this Section.
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(c) Use of renewable energy credits.
(1) Renewable energy credits that are not used by an
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| alternative retail electric supplier to comply with a renewable portfolio standard in a compliance year may be banked and carried forward up to 2 12-month compliance periods after the compliance period in which the credit was generated for the purpose of complying with a renewable portfolio standard in those 2 subsequent compliance periods. For the 2009-2010 and 2010-2011 compliance periods, an alternative retail electric supplier may use renewable credits generated after December 31, 2008 and before June 1, 2009 to comply with this Section.
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(2) An alternative retail electric supplier is
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| responsible for demonstrating that a renewable energy credit used to comply with a renewable portfolio standard is derived from a renewable energy resource and that the alternative retail electric supplier has not used, traded, sold, or otherwise transferred the credit.
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(3) The same renewable energy credit may be used by
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| an alternative retail electric supplier to comply with a federal renewable portfolio standard and a renewable portfolio standard established under this Act. An alternative retail electric supplier that uses a renewable energy credit to comply with a renewable portfolio standard imposed by any other state may not use the same credit to comply with a renewable portfolio standard established under this Act.
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(d) Alternative compliance payments.
(1) The Commission shall establish and post on its
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| website, within 5 business days after entering an order approving a procurement plan pursuant to Section 1-75 of the Illinois Power Agency Act, maximum alternative compliance payment rates, expressed on a per kilowatt-hour basis, that will be applicable in the first compliance period following the plan approval. A separate maximum alternative compliance payment rate shall be established for the service territory of each electric utility that is subject to subsection (c) of Section 1-75 of the Illinois Power Agency Act. Each maximum alternative compliance payment rate shall be equal to the maximum allowable annual estimated average net increase due to the costs of the utility's purchase of renewable energy resources included in the amounts paid by eligible retail customers in connection with electric service, as described in item (2) of subsection (c) of Section 1-75 of the Illinois Power Agency Act for the compliance period, and as established in the approved procurement plan. Following each procurement event through which renewable energy resources are purchased for one or more of these utilities for the compliance period, the Commission shall establish and post on its website estimates of the alternative compliance payment rates, expressed on a per kilowatt-hour basis, that shall apply for that compliance period. Posting of the estimates shall occur no later than 10 business days following the procurement event, however, the Commission shall not be required to establish and post such estimates more often than once per calendar month. By July 1 of each year, the Commission shall establish and post on its website the actual alternative compliance payment rates for the preceding compliance year. For compliance years beginning prior to June 1, 2014, each alternative compliance payment rate shall be equal to the total amount of dollars that the utility contracted to spend on renewable resources, excepting the additional incremental cost attributable to solar resources, for the compliance period divided by the forecasted load of eligible retail customers, at the customers' meters, as previously established in the Commission-approved procurement plan for that compliance year. For compliance years commencing on or after June 1, 2014, each alternative compliance payment rate shall be equal to the total amount of dollars that the utility contracted to spend on all renewable resources for the compliance period divided by the forecasted load of retail customers for which the utility is procuring renewable energy resources in a given delivery year, at the customers' meters, as previously established in the Commission-approved procurement plan for that compliance year. The actual alternative compliance payment rates may not exceed the maximum alternative compliance payment rates established for the compliance period. For purposes of this subsection (d), the term "eligible retail customers" has the same meaning as found in Section 16-111.5 of this Act.
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(2) In any given compliance year, an alternative
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| retail electric supplier may elect to use alternative compliance payments to comply with all or a part of the applicable renewable portfolio standard. In the event that an alternative retail electric supplier elects to make alternative compliance payments to comply with all or a part of the applicable renewable portfolio standard, such payments shall be made by September 1, 2010 for the period of June 1, 2009 to May 1, 2010 and by September 1 of each year thereafter for the subsequent compliance period, in the manner and form as determined by the Commission. Any election by an alternative retail electric supplier to use alternative compliance payments is subject to review by the Commission under subsection (e) of this Section.
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(3) An alternative retail electric supplier's
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| alternative compliance payments shall be computed separately for each electric utility's service territory within which the alternative retail electric supplier provided retail service during the compliance period, provided that the electric utility was subject to subsection (c) of Section 1-75 of the Illinois Power Agency Act. For each service territory, the alternative retail electric supplier's alternative compliance payment shall be equal to (i) the actual alternative compliance payment rate established in item (1) of this subsection (d), multiplied by (ii) the actual amount of metered electricity delivered by the alternative retail electric supplier to retail customers for which the supplier has a compliance obligation within the service territory during the compliance period, multiplied by (iii) the result of one minus the ratios of the quantity of renewable energy resources used by the alternative retail electric supplier to comply with the requirements of this Section within the service territory to the product of the percentage of renewable energy resources required under item (3) or (3.5) of subsection (a) of this Section and the actual amount of metered electricity delivered by the alternative retail electrical supplier to retail customers for which the supplier has a compliance obligation within the service territory during the compliance period.
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(4) Through May 31, 2017, all alternative compliance
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| payments by alternative retail electric suppliers shall be deposited in the Illinois Power Agency Renewable Energy Resources Fund and used to purchase renewable energy credits, in accordance with Section 1-56 of the Illinois Power Agency Act. Beginning April 1, 2012 and by April 1 of each year thereafter, the Illinois Power Agency shall submit an annual report to the General Assembly, the Commission, and alternative retail electric suppliers that shall include, but not be limited to:
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(A) the total amount of alternative compliance
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| payments received in aggregate from alternative retail electric suppliers by planning year for all previous planning years in which the alternative compliance payment was in effect;
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(B) the amount of those payments utilized to
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| purchased renewable energy credits itemized by the date of each procurement in which the payments were utilized; and
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(C) the unused and remaining balance in the
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| Agency Renewable Energy Resources Fund attributable to those payments.
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(4.5) Beginning with the delivery year commencing
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| June 1, 2017, all alternative compliance payments by alternative retail electric suppliers shall be remitted to the applicable electric utility. To facilitate this remittance, each electric utility shall file a tariff with the Commission no later than 30 days following the effective date of this amendatory Act of the 99th General Assembly, which the Commission shall approve, after notice and hearing, no later than 45 days after its filing. The Illinois Power Agency shall use such payments to increase the amount of renewable energy resources otherwise to be procured under subsection (c) of Section 1-75 of the Illinois Power Agency Act.
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(5) The Commission, in consultation with the
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| Illinois Power Agency, shall establish a process or proceeding to consider the impact of a federal renewable portfolio standard, if enacted, on the operation of the alternative compliance mechanism, which shall include, but not be limited to, developing, to the extent permitted by the applicable federal statute, an appropriate methodology to apportion renewable energy credits retired as a result of alternative compliance payments made in accordance with this Section. The Commission shall commence any such process or proceeding within 35 days after enactment of a federal renewable portfolio standard.
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(e) Each alternative retail electric supplier shall, by September 1, 2010 and by September 1 of each year thereafter, prepare and submit to the Commission a report, in a format to be specified by the Commission, that provides information certifying compliance by the alternative retail electric supplier with this Section, including copies of all PJM-GATS and M-RETS reports, and documentation relating to banking, retiring renewable energy credits, and any other information that the Commission determines necessary to ensure compliance with this Section.
An alternative retail electric supplier may file commercially or financially sensitive information or trade secrets with the Commission as provided under the rules of the Commission. To be filed confidentially, the information shall be accompanied by an affidavit that sets forth both the reasons for the confidentiality and a public synopsis of the information.
(f) The Commission may initiate a contested case to review allegations that the alternative retail electric supplier has violated this Section, including an order issued or rule promulgated under this Section. In any such proceeding, the alternative retail electric supplier shall have the burden of proof. If the Commission finds, after notice and hearing, that an alternative retail electric supplier has violated this Section, then the Commission shall issue an order requiring the alternative retail electric supplier to:
(1) immediately comply with this Section; and
(2) if the violation involves a failure to procure
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| the requisite quantity of renewable energy resources or pay the applicable alternative compliance payment by the annual deadline, the Commission shall require the alternative retail electric supplier to double the applicable alternative compliance payment that would otherwise be required to bring the alternative retail electric supplier into compliance with this Section.
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If an alternative retail electric supplier fails to comply with the renewable energy resource portfolio requirement in this Section more than once in a 5-year period, then the Commission shall revoke the alternative electric supplier's certificate of service authority. The Commission shall not accept an application for a certificate of service authority from an alternative retail electric supplier that has lost certification under this subsection (f), or any corporate affiliate thereof, for at least one year after the date of revocation.
(g) All of the provisions of this Section apply to electric utilities operating outside their service area except under item (2) of subsection (a) of this Section the quantity of renewable energy resources shall be measured as a percentage of the actual amount of electricity (megawatt-hours) supplied in the State outside of the utility's service territory during the 12-month period June 1 through May 31, commencing June 1, 2009, and the comparable 12-month period in each year thereafter except as provided in item (6) of subsection (a) of this Section.
If any such utility fails to procure the requisite quantity of renewable energy resources by the annual deadline, then the Commission shall require the utility to double the alternative compliance payment that would otherwise be required to bring the utility into compliance with this Section.
If any such utility fails to comply with the renewable energy resource portfolio requirement in this Section more than once in a 5-year period, then the Commission shall order the utility to cease all sales outside of the utility's service territory for a period of at least one year.
(h) The provisions of this Section and the provisions of subsection (d) of Section 16-115 of this Act relating to procurement of renewable energy resources shall not apply to an alternative retail electric supplier that operates a combined heat and power system in this State or that has a corporate affiliate that operates such a combined heat and power system in this State that supplies electricity primarily to or for the benefit of: (i) facilities owned by the supplier, its subsidiary, or other corporate affiliate; (ii) facilities electrically integrated with the electrical system of facilities owned by the supplier, its subsidiary, or other corporate affiliate; or (iii) facilities that are adjacent to the site on which the combined heat and power system is located.
(i) The obligations of alternative retail electric suppliers and electric utilities operating outside their service territories to procure renewable energy resources, make alternative compliance payments, and file annual reports, and the obligations of the Commission to determine and post alternative compliance payment rates, shall terminate after May 31, 2019, provided that alternative retail electric suppliers and electric utilities operating outside their service territories shall be obligated to make all alternative compliance payments that they were obligated to pay for periods through and including May 31, 2019, but were not paid as of that date. The Commission shall continue to enforce the payment of unpaid alternative compliance payments in accordance with subsections (f) and (g) of this Section. All alternative compliance payments made after May 31, 2016 shall be remitted to the applicable electric utility and used to purchase renewable energy credits, in accordance with Section 1-75 of the Illinois Power Agency Act.
This subsection (i) is intended to accommodate the transition to the procurement of renewable energy resources for all retail customers in the amounts specified under subsection (c) of Section 1-75 of the Illinois Power Agency Act and Section 16-111.5 of this Act, including but not limited to the transition to a single charge applicable to all retail customers to recover the costs of these resources. Each alternative retail electric supplier shall certify in its annual reports filed pursuant to subsection (e) of this Section after May 31, 2019, that its retail customers are not paying the costs of alternative compliance payments or renewable energy resources that the alternative retail electric supplier is not required to remit or purchase under this Section. The Commission shall have the authority to initiate an emergency rulemaking to adopt rules regarding such certification.
(Source: P.A. 99-906, eff. 6-1-17 .)
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