103RD GENERAL ASSEMBLY State of Illinois 2023 and 2024 SB3637 Introduced 2/9/2024, by Sen. Bill Cunningham SYNOPSIS AS INTRODUCED: See Index Creates the Municipal and Cooperative Electric Utility Planning and Transparency Act. Provides that, by November 1, 2024, and by November 1 every 3 years thereafter, all electric cooperatives with members in the State, municipal power agencies, and municipalities shall file with the Illinois Power Agency an integrated resource plan. Sets forth provisions concerning the plan. Amends the Illinois Power Agency Act. Authorizes the Illinois Power Agency to develop capacity procurement plans and conduct competitive procurement processes for the procurement of capacity needed to ensure environmentally sustainable long-term resource adequacy across the State at the lowest cost over time. Amends the Public Utilities Act. Changes the cumulative persisting annual savings goals for electric utilities that serve less than 3,000,000 retail customers but more than 500,000 retail customers for the years of 2024 through 2030. Provides that the cumulative persisting annual savings goals beyond the year 2030 shall increase by 0.9 (rather than 0.6) percentage points per year. Changes the requirements for submitting proposed plans and funding levels to meet savings goals for an electric utility serving more than 500,000 retail customers (rather than serving less than 3,000,000 retail customers but more than 500,000 retail customers). Provides that an electric utility that has a tariff approved within one year of the amendatory Act shall also offer at least one market-based, time-of-use rate for eligible retail customers that choose to take power and energy supply service from the utility. Sets forth provisions regarding the Illinois Commerce Commission's powers and duties related to residential time-of-use pricing. Provides that each capacity procurement event may include the procurement of capacity through a mix of contracts with different terms and different initial delivery dates. Sets forth the requirements of prepared capacity procurement plans. Requires each alternative electric supplier to make payment to an applicable electric utility for capacity, receive transfers of capacity credits, report capacity credits procured on its behalf to the applicable regional transmission organization, and submit the capacity credits to the applicable regional transmission organization under that regional transmission organization's rules and procedures. Makes other changes. LRB103 38841 CES 68978 b A BILL FOR 103RD GENERAL ASSEMBLY State of Illinois 2023 and 2024 SB3637 Introduced 2/9/2024, by Sen. Bill Cunningham SYNOPSIS AS INTRODUCED: See Index See Index Creates the Municipal and Cooperative Electric Utility Planning and Transparency Act. Provides that, by November 1, 2024, and by November 1 every 3 years thereafter, all electric cooperatives with members in the State, municipal power agencies, and municipalities shall file with the Illinois Power Agency an integrated resource plan. Sets forth provisions concerning the plan. Amends the Illinois Power Agency Act. Authorizes the Illinois Power Agency to develop capacity procurement plans and conduct competitive procurement processes for the procurement of capacity needed to ensure environmentally sustainable long-term resource adequacy across the State at the lowest cost over time. Amends the Public Utilities Act. Changes the cumulative persisting annual savings goals for electric utilities that serve less than 3,000,000 retail customers but more than 500,000 retail customers for the years of 2024 through 2030. Provides that the cumulative persisting annual savings goals beyond the year 2030 shall increase by 0.9 (rather than 0.6) percentage points per year. Changes the requirements for submitting proposed plans and funding levels to meet savings goals for an electric utility serving more than 500,000 retail customers (rather than serving less than 3,000,000 retail customers but more than 500,000 retail customers). Provides that an electric utility that has a tariff approved within one year of the amendatory Act shall also offer at least one market-based, time-of-use rate for eligible retail customers that choose to take power and energy supply service from the utility. Sets forth provisions regarding the Illinois Commerce Commission's powers and duties related to residential time-of-use pricing. Provides that each capacity procurement event may include the procurement of capacity through a mix of contracts with different terms and different initial delivery dates. Sets forth the requirements of prepared capacity procurement plans. Requires each alternative electric supplier to make payment to an applicable electric utility for capacity, receive transfers of capacity credits, report capacity credits procured on its behalf to the applicable regional transmission organization, and submit the capacity credits to the applicable regional transmission organization under that regional transmission organization's rules and procedures. Makes other changes. LRB103 38841 CES 68978 b LRB103 38841 CES 68978 b A BILL FOR
103RD GENERAL ASSEMBLY State of Illinois 2023 and 2024 SB3637 Introduced 2/9/2024, by Sen. Bill Cunningham SYNOPSIS AS INTRODUCED:
See Index See Index
See Index
Creates the Municipal and Cooperative Electric Utility Planning and Transparency Act. Provides that, by November 1, 2024, and by November 1 every 3 years thereafter, all electric cooperatives with members in the State, municipal power agencies, and municipalities shall file with the Illinois Power Agency an integrated resource plan. Sets forth provisions concerning the plan. Amends the Illinois Power Agency Act. Authorizes the Illinois Power Agency to develop capacity procurement plans and conduct competitive procurement processes for the procurement of capacity needed to ensure environmentally sustainable long-term resource adequacy across the State at the lowest cost over time. Amends the Public Utilities Act. Changes the cumulative persisting annual savings goals for electric utilities that serve less than 3,000,000 retail customers but more than 500,000 retail customers for the years of 2024 through 2030. Provides that the cumulative persisting annual savings goals beyond the year 2030 shall increase by 0.9 (rather than 0.6) percentage points per year. Changes the requirements for submitting proposed plans and funding levels to meet savings goals for an electric utility serving more than 500,000 retail customers (rather than serving less than 3,000,000 retail customers but more than 500,000 retail customers). Provides that an electric utility that has a tariff approved within one year of the amendatory Act shall also offer at least one market-based, time-of-use rate for eligible retail customers that choose to take power and energy supply service from the utility. Sets forth provisions regarding the Illinois Commerce Commission's powers and duties related to residential time-of-use pricing. Provides that each capacity procurement event may include the procurement of capacity through a mix of contracts with different terms and different initial delivery dates. Sets forth the requirements of prepared capacity procurement plans. Requires each alternative electric supplier to make payment to an applicable electric utility for capacity, receive transfers of capacity credits, report capacity credits procured on its behalf to the applicable regional transmission organization, and submit the capacity credits to the applicable regional transmission organization under that regional transmission organization's rules and procedures. Makes other changes.
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1 AN ACT concerning regulation.
2 Be it enacted by the People of the State of Illinois,
3 represented in the General Assembly:
4 Section 1. Short title. This Act may be cited as the
5 Municipal and Cooperative Electric Utility Planning and
6 Transparency Act.
7 Section 5. Legislative findings and objectives. The
8 General Assembly finds:
9 (1) Municipal and cooperative electric utilities
10 provide electricity to more than 1,000,000 State
11 residents.
12 (2) These utilities are managed by elected officials,
13 elected board members, or their appointees. Due to their
14 governance structures, municipal and cooperative electric
15 utilities are exempt from certain regulatory requirements
16 and oversight under State and federal law.
17 (3) State residents who are served by these utilities,
18 and who pay rates for electricity set by these utilities,
19 often lack access to important information about these
20 utilities' generation portfolios, procurement, management
21 practices, and budgets. Because democratic elections by
22 member-ratepayers or customers are the ultimate guarantor
23 of the integrity and cost-effectiveness of these
103RD GENERAL ASSEMBLY State of Illinois 2023 and 2024 SB3637 Introduced 2/9/2024, by Sen. Bill Cunningham SYNOPSIS AS INTRODUCED:
See Index See Index
See Index
Creates the Municipal and Cooperative Electric Utility Planning and Transparency Act. Provides that, by November 1, 2024, and by November 1 every 3 years thereafter, all electric cooperatives with members in the State, municipal power agencies, and municipalities shall file with the Illinois Power Agency an integrated resource plan. Sets forth provisions concerning the plan. Amends the Illinois Power Agency Act. Authorizes the Illinois Power Agency to develop capacity procurement plans and conduct competitive procurement processes for the procurement of capacity needed to ensure environmentally sustainable long-term resource adequacy across the State at the lowest cost over time. Amends the Public Utilities Act. Changes the cumulative persisting annual savings goals for electric utilities that serve less than 3,000,000 retail customers but more than 500,000 retail customers for the years of 2024 through 2030. Provides that the cumulative persisting annual savings goals beyond the year 2030 shall increase by 0.9 (rather than 0.6) percentage points per year. Changes the requirements for submitting proposed plans and funding levels to meet savings goals for an electric utility serving more than 500,000 retail customers (rather than serving less than 3,000,000 retail customers but more than 500,000 retail customers). Provides that an electric utility that has a tariff approved within one year of the amendatory Act shall also offer at least one market-based, time-of-use rate for eligible retail customers that choose to take power and energy supply service from the utility. Sets forth provisions regarding the Illinois Commerce Commission's powers and duties related to residential time-of-use pricing. Provides that each capacity procurement event may include the procurement of capacity through a mix of contracts with different terms and different initial delivery dates. Sets forth the requirements of prepared capacity procurement plans. Requires each alternative electric supplier to make payment to an applicable electric utility for capacity, receive transfers of capacity credits, report capacity credits procured on its behalf to the applicable regional transmission organization, and submit the capacity credits to the applicable regional transmission organization under that regional transmission organization's rules and procedures. Makes other changes.
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A BILL FOR
See Index
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1 utilities' operations, access to this information is
2 crucial to ensuring management of these utilities is
3 prudent and responsive.
4 (4) Good utility practice entails long-term planning
5 on the part of a utility, including anticipating
6 retirement of existing generation resources, planning new
7 generation build or purchase well in advance of any
8 capacity shortfall, and developing rigorous estimates of
9 future load to inform procurement, construction, and
10 retirement decisions.
11 (5) In many other states, integrated resource planning
12 processes have been used to avoid capacity shortfalls,
13 minimize ratepayer costs, and increase public
14 participation in and knowledge of electric generation
15 portfolio choices, even where the planning utility is not
16 otherwise subject to rate approval by the state.
17 (6) It is in the best interests of State electricity
18 customers and member-ratepayers that electricity is
19 provided by a portfolio of generation and storage
20 resources and demand-side programs that minimizes both
21 cost and environmental impacts and that long-term utility
22 planning can and should facilitate the achievement of such
23 portfolios.
24 (7) With the enactment of the Inflation Reduction Act
25 of 2022, municipal and cooperative electric utilities have
26 access to a variety of federal funding streams designed to
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1 facilitate transition from fossil fuel to renewable
2 generation. Consistent with Congressional intent,
3 municipal and cooperative electric utilities should
4 perform a comprehensive analysis of their existing
5 portfolio and have a duty, as utility managers, to
6 identify opportunities to minimize member-ratepayer and
7 customer costs.
8 (8) To ensure utilities minimize ratepayer costs,
9 maximize opportunities for transition from fossil fuels to
10 renewable resources, and to increase transparency and
11 democratic participation, it is important that municipal
12 and cooperative electric utilities participate in an
13 integrated resource planning process with public
14 participation and Illinois Power Agency oversight.
15 Section 10. Definitions. As used in this Act:
16 "Agency" means the Illinois Power Agency.
17 "Demand-side program" means a program implemented by or on
18 behalf of a utility to reduce retail customer consumption
19 (MWh) or shift the time of consumption of energy (MW) from end
20 users, including energy efficiency programs, demand-response
21 programs, and programs for the promotion or aggregation of
22 distributed generation.
23 "Electric cooperative" has the meaning given to that term
24 in Section 3-119 of the Public Utilities Act.
25 "Generation resource" means a facility for the generation
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1 of electricity.
2 "Municipal power agency" has the meaning given to that
3 term in Section 11-119.1-3 of the Illinois Municipal Code.
4 "Municipality" has the meaning given to that term in
5 Section 11-119.1-3 of the Illinois Municipal Code.
6 "Renewable generation resource" means a resource for
7 generating electricity that uses wind, solar, or geothermal
8 energy.
9 "Storage resource" means a commercially available
10 technology that uses mechanical, chemical, or thermal
11 processes to store energy and deliver the stored energy as
12 electricity for use at a later time and is capable of being
13 controlled by the distribution or transmission entity managing
14 it, to enable and optimize the safe and reliable operation of
15 the electric system.
16 "Utility" means a municipal power agency, municipality, or
17 electric cooperative.
18 Section 15. Purpose and contents of integrated resource
19 plan.
20 (a) By November 1, 2024, and by November 1 every 3 years
21 thereafter, all electric cooperatives with members in this
22 State, municipal power agencies, and municipalities shall file
23 with the Agency an integrated resource plan, except that
24 municipalities and electric cooperatives that are members of,
25 and have a full requirements contract with, a municipal power
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1 agency or electric cooperative subject to this Act may file a
2 statement adopting such other utility's integrated resource
3 plan.
4 (b) The purposes of the integrated resource plan are to
5 provide a comprehensive description of the utility's current
6 portfolio of electrical generation, storage, demand-side
7 programs, and transmission resources, to forecast future load
8 changes to facilitate prudent planning with respect to
9 resource procurement and retirement, to determine what
10 resource portfolio will meet ratepayers' needs while
11 minimizing cost and environmental impact, and to articulate
12 steps the utility will take to reduce customer costs and
13 environmental impacts through changes to its current
14 generation portfolio through construction, procurement,
15 retirement, or demand-side programs.
16 (c) As part of the integrated resource plan development
17 process, a utility shall consider all resources reasonably
18 available or reasonably likely to be available during the
19 relevant time period to satisfy the demand for electricity
20 services for a 20-year planning period, taking into account
21 both supply-side and demand-side electric power resources.
22 (d) An integrated resource plan shall include, at a
23 minimum:
24 (1) A list of all electricity generation facilities
25 owned by the utility, in whole or in part. For each such
26 facility, the integrated resource plan shall report:
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1 (A) general location;
2 (B) ownership information, if ownership is shared
3 with another entity;
4 (C) type of fuel;
5 (D) the date of commercial operation;
6 (E) expected useful life;
7 (F) expected retirement date for any resource
8 expected to retire within the next 10 years, and an
9 explanation of the reason for the retirement;
10 (G) nameplate and peak available capacity;
11 (H) total MWh generated at the facility during the
12 previous calendar year;
13 (I) the date on which the facility is anticipated
14 to be fully depreciated; and
15 (J) any compliance obligations, or compliance
16 obligations expected to apply within the next 10
17 years, and any proposed or anticipated expenditures
18 intended to meet those obligations.
19 (2) A list of all power purchase agreements to which
20 the utility is a party, whether as purchaser or seller,
21 including the counterparty, general location and type of
22 generation resource providing power per the agreement,
23 date on which the agreement was entered into, duration of
24 the agreement, and the energy and capacity terms of the
25 agreement.
26 (3) A list of any sale transactions of any energy or
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1 capacity to any purchaser.
2 (4) A list of any demand-side programs and total
3 distributed generation.
4 (5) A narrative description of all existing
5 transmission facilities owned by the utility, in whole or
6 in part, that identifies any transmission constraints or
7 critical contingencies, and identification of the regional
8 transmission organization, if any, which exercises
9 operational control over the transmission facility.
10 (6) A list of all capital expenditures exceeding
11 $1,000,000 in the previous calendar year that includes a
12 brief description of the expenditure, the total amount
13 expended, and whether the expenditure was required to
14 conform with State or federal law, rule, or regulation;
15 (7) A description of all transmission costs,
16 disaggregated by expenditure, that identifies all capital
17 expenditures on physical infrastructure and contracts for
18 rights costing greater than $1,000,000 over the term of
19 the agreement.
20 (8) A copy of the most recent FERC Form 1 filed by the
21 utility. If no such FERC Form 1 has been filed, the utility
22 shall complete a FERC Form 1 for the prior calendar year.
23 (9) A range of load forecasts for the 5-year planning
24 period that includes hourly data representing a high-load,
25 low-load, and expected-load scenario for all retail
26 customers, consistent with the requirements of paragraph
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1 (1) of subsection (d) of Section 16-111.5 of the Public
2 Utilities Act and any associated rules or regulations.
3 Such forecasts shall include:
4 (A) all underlying assumptions;
5 (B) an hourly load analysis consistent with the
6 requirements of paragraph (1) of subsection (b) of
7 Section 16-111.5 of the Public Utilities Act;
8 (C) analysis of the impact of any demand-side
9 programs, consistent with paragraph (2) of subsection
10 (b) of Section 16-111.5 of the Public Utilities Act;
11 (D) any reserve margin or other obligations placed
12 on the utility by regional transmission organizations
13 to which it is a member; and
14 (E) to the extent the information is available, an
15 assessment of the accuracy of any past load forecasts
16 submitted pursuant to this Section and an explanation
17 of any deviation of greater than 10% in either
18 direction from the forecasted load.
19 (10) The results of an all-source request for
20 proposals for generation resources and capacity contracts.
21 (11) A 5-year action plan for meeting the forecasted
22 load that minimizes customer cost and adverse
23 environmental impacts. As part of the action plan, the
24 utility shall:
25 (A) Identify any generation or storage resources
26 anticipated to be removed from service in the 5 years
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1 following the date on which the integrated resource
2 plan is submitted.
3 (B) Determine whether given forecasted load growth
4 or unit retirements, or both, the utility will need to
5 procure additional capacity and energy, and provide a
6 quantitative estimate of any such gap between
7 forecasted load and supply-side resources.
8 (C) Provide a narrative description of the
9 utility's process for evaluating possible resources to
10 secure this additional capacity and energy.
11 (D) Provide a narrative description of the
12 utility's processes for assessing the present economic
13 value of existing generation and state whether,
14 consistent with this methodology, any currently
15 operating units, if any, could be replaced by other
16 resources at lower cost to ratepayers.
17 (E) Identify a preferred portfolio of generation,
18 storage, and demand-side programs that, in the
19 utility's judgment, meets its forecasted load while
20 minimizing the ratepayer cost and environmental
21 impacts to the extent reasonably achievable in the 5
22 years covered by the action plan. The portfolio shall
23 incorporate any capacity or other reliability
24 requirements of any regional transmission organization
25 of which the utility is a member.
26 (F) Identify, if the preferred portfolio includes
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1 the construction of new generation or storage
2 resources or transmission facilities, the preferred
3 site for all new construction of generation, storage,
4 or transmission facilities.
5 (G) If the utility states that it intends to
6 remove a generation resource from service, include in
7 the integrated resource plan a statement describing
8 the utility's plan to minimize economic impacts to
9 workers due to facility retirement. This statement
10 shall include a description of:
11 (i) the utility's efforts to collaborate with
12 the workers and their designated representatives,
13 if any;
14 (ii) a transition timeline or date certain on
15 which such a transition timeline shall be made
16 available to ensure certainty for workers;
17 (iii) the utility's efforts to protect pension
18 benefits and extend or replace health insurance,
19 life insurance, and other employment benefits;
20 (iv) all training and skill development
21 programs to be made available for workers who will
22 see their employment reduced or eliminated as a
23 result of the retirement; and
24 (v) any agreements with local governments
25 regarding continuing tax or other transfer
26 payments following the facility's retirement
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1 intended to minimize the impact on local services.
2 (H) Describe any anticipated capital expenditures
3 in excess of $1,000,000 at existing generation
4 facilities and the reason for such expenditures.
5 (12) A description of all models and methodologies
6 used in performing the integrated resource planning
7 process. The utility shall provide to the Agency, upon
8 request, reasonable access to any computer models used in
9 the analysis and workpapers, in electronic form, relied on
10 in preparation of the report.
11 (e) As part of all integrated resource plans submitted in
12 2024, the utility shall identify all programs, grants, loans,
13 or tax benefits for which the utility is eligible pursuant to
14 the Inflation Reduction Act of 2022, and state whether the
15 utility has applied for or otherwise used the program, grant,
16 loan, or tax benefit. If the utility has not yet applied for or
17 utilized the benefit, the utility shall state whether it
18 intends to do so.
19 (f) Each utility shall submit, as part of its integrated
20 resource plan, a least cost plan for constructing or procuring
21 renewable energy resources to meet a minimum percentage of its
22 load for all retail customers as follows: 25% by June 1, 2026,
23 increasing by at least 3% each delivery year thereafter to at
24 least 40% by the 2030 delivery year, and continuing at no less
25 than 40% for each delivery year thereafter.
26 (g) Beginning in 2031, each utility shall submit, as part
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1 of its integrated resource plan, a least cost plan for
2 supplying 100% of its total projected load through renewable
3 generation resources in combination with storage resources and
4 demand-side programs by 2045. This least cost plan shall
5 provide for the retirement of all coal and gas generation
6 resources by January 1, 2045.
7 (h) The Agency may adopt rules establishing additional
8 requirements as to the form and content of integrated resource
9 plans, including, but not limited to, specifying forecast
10 methodologies.
11 Section 20. Stakeholder process. Prior to the submission
12 of an integrated resource plan, a municipality, municipal
13 power agency, or electric cooperative required to submit an
14 integrated resource plan shall hold at least 2 stakeholders
15 meetings open to all ratepayers and members of the public.
16 Notice of the meetings shall be sent to all customers not less
17 than 30 days prior to the meeting. During the meetings the
18 utility shall describe its processes for developing the
19 integrated resource plan and its core assumptions and
20 constraints, present its proposed preferred portfolio, and
21 describe any planned retirements, capital expenditures on
22 existing generation resources likely to exceed $1,000,000, and
23 planned construction. Each meeting shall allow time for public
24 comment and the utility shall provide attendees with a means
25 of providing public comment in writing following the meeting.
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1 Section 25. Procedures for submission of integrated
2 resource plan.
3 (a) Each municipality, municipal power agency, and
4 electric cooperative shall submit its integrated resource
5 plan, as set forth in this Act, to the Agency by October 1 of
6 the calendar year.
7 (b) The Agency may request further information from the
8 utility. Any such requests shall be made in writing. If the
9 Agency requests additional information, the utility shall
10 provide responses no later than 15 days following the request.
11 (c) The Agency shall facilitate public comment on the
12 integrated resource plan, as follows:
13 (1) upon submission of the integrated resource plan,
14 the Agency shall post the integrated resource plan
15 publicly on its website. The plan shall remain publicly
16 accessible for at least 60 days.
17 (2) the utility shall hold at least 2 public meetings,
18 one in person and one remotely, where it shall make a
19 representative available to address questions about the
20 resource plan. The meetings shall be held no sooner than
21 15 days, and no later than 45 days, after the integrated
22 resource plan is made available to the public.
23 (3) the Agency shall accept public comments on the
24 integrated resource plan for 60 days following its public
25 posting via website, email, or mail. The Agency may extend
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1 this public comment period by an additional 60 days upon
2 request by members of the public; and
3 (4) after the conclusion of the public comment period,
4 as determined by the Agency, the Agency shall transmit
5 copies of all public comments received to the utility.
6 (d) The utility shall review public comments and provide
7 responses that reasonably address all issues or questions
8 raised by such comments. The utility may modify its integrated
9 resource plan in response to these comments. The utility shall
10 prepare a document with responses to public comments and
11 submit this response document to the Agency no later than 90
12 days after receiving the comments from the agency. This
13 response document shall be posted publicly on the Agency's
14 website along with the original integrated resource plan, as
15 submitted, and any revisions made by the utility in response
16 to public comments.
17 (e) The Agency shall maintain public access to all
18 integrated resource plans submitted pursuant to this Act,
19 accessible through the Agency's website, for no less than 10
20 years following each integrated resource plan's initial
21 submission.
22 Section 30. Cost of Service Study.
23 (a) All electric cooperatives with members in this State,
24 municipal power agencies, and municipalities with $5,000,000
25 or more in total retail electricity revenues shall submit to
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1 the Agency an embedded cost-of-service study on November 1,
2 2024 and on November 1 every 3 years thereafter.
3 (b) The format and contents of such study shall be
4 consistent with those set forth in any rules or regulations by
5 the Illinois Commerce Commission for cost-of-service studies
6 by electric utilities subject to retail rate approval by the
7 Commerce Commission.
8 Section 35. Use of independent expert.
9 (a) The Agency shall maintain a list of qualified experts
10 or expert consulting firms for the purpose of developing
11 integrated resource plans on behalf of municipalities,
12 municipal power agencies, and cooperatives. In order to
13 qualify an expert or expert consulting firm must have:
14 (1) direct previous experience assembling power supply
15 plans or portfolios for utilities;
16 (2) an advanced degree in economics, mathematics,
17 engineering, risk management, or a related area of study;
18 (3) 10 years of experience in the electricity sector;
19 (4) expertise in wholesale electricity market rules,
20 including those established by the federal Energy
21 Regulatory Commission and regional transmission
22 organizations; and
23 (5) adequate resources to perform and fulfill the
24 required functions and responsibilities.
25 (b) The Agency may assemble the list as part of the process
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1 for developing a list of qualified experts for experts to
2 develop procurement plans, as set forth in subsection (a) of
3 Section 1-75 of the Illinois Power Agency Act.
4 (c) The Agency shall provide affected utilities and other
5 interested parties with the lists of qualified experts or
6 expert consulting firms identified through the request for
7 qualifications processes that are under consideration to
8 prepare the integrated resource plan on behalf of the utility.
9 The Agency shall also provide each qualified expert's or
10 expert consulting firm's response to the request for
11 qualifications. A utility shall, within 5 business days,
12 notify the Agency in writing if it objects to any experts or
13 expert consulting firms on the lists. Objections shall be
14 based on:
15 (1) the failure to satisfy qualification criteria;
16 (2) the identification of a conflict of interest; or
17 (3) the evidence of inappropriate bias for or against
18 potential bidders or the affected utilities.
19 The Agency shall remove experts or expert consulting firms
20 from the lists within 10 days if there is a reasonable basis
21 for an objection and provide the updated lists to the affected
22 utilities and other interested parties. If the Agency fails to
23 remove an expert or expert consulting firm from the list, the
24 objecting utility may withdraw its application and develop its
25 integrated resource plan without agency assistance.
26 (d) A utility required to submit an integrated resource
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1 plan may elect to rely on an expert or expert consulting firm
2 selected by the Agency to develop the plan and conduct
3 stakeholder processes.
4 (e) A utility may submit a request to the Agency, not less
5 than 6 months prior to the date on which the integrated
6 resource plan is due, for such an expert or expert consulting
7 firm.
8 (f) Upon receipt of such a request, the Agency shall issue
9 requests for proposals to the qualified experts on the list
10 assembled as set forth in subsections (a) through (c) to
11 develop an integrated resource plan for that utility. The
12 Agency shall select an expert or expert consulting firm to
13 develop the integrated resource plan on behalf of the utility
14 based on the proposals submitted.
15 (g) Subject to appropriation, if a utility elects to rely
16 on an expert or expert consulting firm selected by the Agency,
17 90% of the costs assessed by the expert for development of the
18 integrated resource plan shall be paid by the Agency, up to
19 $250,000, and the remainder paid by the utility.
20 Section 40. Electric cooperatives member access.
21 (a) As used in this Section, "meeting" has the meaning
22 given to that term in Section 1.02 of the Open Meetings Act.
23 (b) As used in this Section, except for subsection (j),
24 "member" includes all members of an electric cooperative in
25 accordance with the cooperative's bylaws. Where a generation
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1 and transmission electric cooperative's members are electric
2 cooperatives rather than individuals, members of those
3 member-cooperatives are members of the generation and
4 transmission electric cooperative for purposes of this
5 Section. As used in subsection (j), "member" includes only
6 members of an electric cooperative with individual members.
7 (c) All meetings of an electric cooperative shall be open
8 to all members, except that a cooperative, by a two-thirds
9 affirmative vote of the board members present, may go into
10 executive session for consideration of documents or
11 information deemed to be confidential for legal, commercial,
12 or personnel purposes.
13 (1) Before a board of directors convenes in executive
14 session, the board shall announce the general topic of the
15 executive session.
16 (2) Notice of all meetings of an electric cooperative
17 shall be posted on the website of the electric cooperative
18 at least 30 days prior to the meeting, except for any
19 annual meeting, which shall be posted at least 120 days
20 prior. Minutes of all meetings of an electric cooperative
21 shall be posted on the website of the electric cooperative
22 as soon as they have been approved and shall remain posted
23 for at least one year after the date of the meeting. Upon
24 request of a member, the electric cooperative shall make
25 minutes of any meeting held after the effective date of
26 this Act available. Minutes shall include the votes of
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1 each member of the board on all items for which approval
2 was not unanimous.
3 (3) At every regular meeting of the governing body of
4 an electric cooperative, members of the cooperative shall
5 be given an opportunity to address the board on any matter
6 concerning the policies and businesses of the cooperative.
7 The board may place reasonable, viewpoint-neutral
8 restrictions on the amount and duration of member comment.
9 (d) Each electric cooperative shall post on its website
10 its current rates. The electric cooperative shall keep and
11 make available to any member, upon request, all financial
12 audits of the electric cooperative conducted in the last 3
13 fiscal years.
14 (e) Each electric cooperative shall adopt and post a
15 written policy governing the election of directors on its
16 website. The electric cooperative shall provide notice of the
17 policy at the time a person becomes a member, as a bill insert
18 at least once per year, and on request. The policy shall
19 contain true and complete information on the following:
20 (1) Who is entitled to vote in an election, including
21 how member cooperatives may vote.
22 (2) How a member may obtain and cast a ballot.
23 (3) The postmark deadline for any ballots submitted by
24 mail.
25 (4) How a member may become a candidate for the board
26 or any other elected leadership positions.
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1 (f) Electric cooperatives shall enable their members to
2 vote in any election for one or more directors by mail-in
3 ballot, as follows:
4 (1) The electric cooperative shall affirmatively mail
5 each of its members a ballot no later than 30 days before
6 ballots are due. Ballots may be mailed separately and
7 clearly marked as such or included as a bill insert.
8 (2) The electric cooperative shall accept ballots by
9 mail if postmarked by the date indicated in the
10 cooperative's written policy.
11 (3) The electric cooperative may allow for in-person
12 voting in addition to mail.
13 (g) Electric cooperatives may establish a system for
14 online voting in addition to a mail-in option.
15 (h) At least 120 days before each board election, the
16 electric cooperative shall post a list of candidates and
17 deadline to return ballots on its website and leave the
18 information posted until the election has concluded. The same
19 information shall be included as part of a bill insert for a
20 billing cycle occurring at no more than 120 but no fewer than
21 15 days prior to the deadline to return ballots.
22 (i) Each candidate for a position on the board of
23 directors who has qualified under the electric cooperative's
24 bylaws is entitled to receive a membership list in electronic
25 format upon receipt and verification of any candidacy
26 requirements. Such a list shall be provided to a candidate no
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1 later than 15 days after requested by the candidate. The
2 membership list must include the names, phone numbers, and
3 addresses of all members as they appear in the electric
4 cooperative's records.
5 Section 45. Conflict of interest.
6 (a) Each electric cooperative, municipality, and municipal
7 power agency shall adopt, and post publicly on its website,
8 written policies concerning:
9 (1) The compensation provided to a director on the
10 board of directors, including information on any
11 authorized per diem amounts, and the values of other
12 benefits, services, or goods that a director receives.
13 (2) The disclosure of any gifts received by a director
14 in excess of a de minimis amount.
15 (3) The requirements and procedures for a director on
16 the board of directors to disclose in writing any
17 conflicts of interest. At a minimum, the policy must
18 require disclosure when a decision before the board could
19 provide directly and as a proximate result of the decision
20 a financial or other material benefit to:
21 (A) The director, if the benefit is unique to that
22 director and not shared by similarly situated
23 cooperative members.
24 (B) A parent, grandparent, spouse, partner in a
25 civil union, child, or sibling of the director, if the
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1 benefit is unique to that director and not shared by
2 similarly situated cooperative members.
3 (C) An entity in which the director is an officer
4 or director or has a financial interest not shared by
5 similarly situated cooperative members.
6 (b) Each electric cooperative shall disclose on its
7 website all lobbying activities as defined by Section 2 of the
8 Lobbyist Registration Act and the amount of expenditures on
9 such activities on an annual basis. Where the electric
10 cooperative is a member of a trade association or other
11 organization that engages in lobbying activities, the electric
12 cooperative shall post the amount of dues or other
13 expenditures paid by the cooperative to such an organization
14 and what percentage of the organization or association's
15 budget is spent on lobbying activities.
16 (c) Notwithstanding any other law to the contrary, if an
17 individual is a director on the board of directors of both a
18 distribution cooperative electric association and a generation
19 and transmission cooperative association, the director owes
20 fiduciary duties to both associations and shall not be
21 required to give priority to a fiduciary duty the director
22 owes to one association over the duties the director owes to
23 the other association.
24 Section 90. The Open Meetings Act is amended by changing
25 Section 2 as follows:
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1 (5 ILCS 120/2) (from Ch. 102, par. 42)
2 Sec. 2. Open meetings.
3 (a) Openness required. All meetings of public bodies shall
4 be open to the public unless excepted in subsection (c) and
5 closed in accordance with Section 2a.
6 (b) Construction of exceptions. The exceptions contained
7 in subsection (c) are in derogation of the requirement that
8 public bodies meet in the open, and therefore, the exceptions
9 are to be strictly construed, extending only to subjects
10 clearly within their scope. The exceptions authorize but do
11 not require the holding of a closed meeting to discuss a
12 subject included within an enumerated exception.
13 (c) Exceptions. A public body may hold closed meetings to
14 consider the following subjects:
15 (1) The appointment, employment, compensation,
16 discipline, performance, or dismissal of specific
17 employees, specific individuals who serve as independent
18 contractors in a park, recreational, or educational
19 setting, or specific volunteers of the public body or
20 legal counsel for the public body, including hearing
21 testimony on a complaint lodged against an employee, a
22 specific individual who serves as an independent
23 contractor in a park, recreational, or educational
24 setting, or a volunteer of the public body or against
25 legal counsel for the public body to determine its
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1 validity. However, a meeting to consider an increase in
2 compensation to a specific employee of a public body that
3 is subject to the Local Government Wage Increase
4 Transparency Act may not be closed and shall be open to the
5 public and posted and held in accordance with this Act.
6 (2) Collective negotiating matters between the public
7 body and its employees or their representatives, or
8 deliberations concerning salary schedules for one or more
9 classes of employees.
10 (3) The selection of a person to fill a public office,
11 as defined in this Act, including a vacancy in a public
12 office, when the public body is given power to appoint
13 under law or ordinance, or the discipline, performance or
14 removal of the occupant of a public office, when the
15 public body is given power to remove the occupant under
16 law or ordinance.
17 (4) Evidence or testimony presented in open hearing,
18 or in closed hearing where specifically authorized by law,
19 to a quasi-adjudicative body, as defined in this Act,
20 provided that the body prepares and makes available for
21 public inspection a written decision setting forth its
22 determinative reasoning.
23 (4.5) Evidence or testimony presented to a school
24 board regarding denial of admission to school events or
25 property pursuant to Section 24-24 of the School Code,
26 provided that the school board prepares and makes
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1 available for public inspection a written decision setting
2 forth its determinative reasoning.
3 (5) The purchase or lease of real property for the use
4 of the public body, including meetings held for the
5 purpose of discussing whether a particular parcel should
6 be acquired.
7 (6) The setting of a price for sale or lease of
8 property owned by the public body.
9 (7) The sale or purchase of securities, investments,
10 or investment contracts. This exception shall not apply to
11 the investment of assets or income of funds deposited into
12 the Illinois Prepaid Tuition Trust Fund.
13 (8) Security procedures, school building safety and
14 security, and the use of personnel and equipment to
15 respond to an actual, a threatened, or a reasonably
16 potential danger to the safety of employees, students,
17 staff, the public, or public property.
18 (9) Student disciplinary cases.
19 (10) The placement of individual students in special
20 education programs and other matters relating to
21 individual students.
22 (11) Litigation, when an action against, affecting or
23 on behalf of the particular public body has been filed and
24 is pending before a court or administrative tribunal, or
25 when the public body finds that an action is probable or
26 imminent, in which case the basis for the finding shall be
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1 recorded and entered into the minutes of the closed
2 meeting.
3 (12) The establishment of reserves or settlement of
4 claims as provided in the Local Governmental and
5 Governmental Employees Tort Immunity Act, if otherwise the
6 disposition of a claim or potential claim might be
7 prejudiced, or the review or discussion of claims, loss or
8 risk management information, records, data, advice or
9 communications from or with respect to any insurer of the
10 public body or any intergovernmental risk management
11 association or self insurance pool of which the public
12 body is a member.
13 (13) Conciliation of complaints of discrimination in
14 the sale or rental of housing, when closed meetings are
15 authorized by the law or ordinance prescribing fair
16 housing practices and creating a commission or
17 administrative agency for their enforcement.
18 (14) Informant sources, the hiring or assignment of
19 undercover personnel or equipment, or ongoing, prior or
20 future criminal investigations, when discussed by a public
21 body with criminal investigatory responsibilities.
22 (15) Professional ethics or performance when
23 considered by an advisory body appointed to advise a
24 licensing or regulatory agency on matters germane to the
25 advisory body's field of competence.
26 (16) Self evaluation, practices and procedures or
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1 professional ethics, when meeting with a representative of
2 a statewide association of which the public body is a
3 member.
4 (17) The recruitment, credentialing, discipline or
5 formal peer review of physicians or other health care
6 professionals, or for the discussion of matters protected
7 under the federal Patient Safety and Quality Improvement
8 Act of 2005, and the regulations promulgated thereunder,
9 including 42 C.F.R. Part 3 (73 FR 70732), or the federal
10 Health Insurance Portability and Accountability Act of
11 1996, and the regulations promulgated thereunder,
12 including 45 C.F.R. Parts 160, 162, and 164, by a
13 hospital, or other institution providing medical care,
14 that is operated by the public body.
15 (18) Deliberations for decisions of the Prisoner
16 Review Board.
17 (19) Review or discussion of applications received
18 under the Experimental Organ Transplantation Procedures
19 Act.
20 (20) The classification and discussion of matters
21 classified as confidential or continued confidential by
22 the State Government Suggestion Award Board.
23 (21) Discussion of minutes of meetings lawfully closed
24 under this Act, whether for purposes of approval by the
25 body of the minutes or semi-annual review of the minutes
26 as mandated by Section 2.06.
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1 (22) Deliberations for decisions of the State
2 Emergency Medical Services Disciplinary Review Board.
3 (23) The operation by a municipality of a municipal
4 utility or the operation of a municipal power agency or
5 municipal natural gas agency when the discussion involves
6 (i) trade secrets, (ii) ongoing contract negotiations or
7 results of a request for proposals relating to the
8 purchase, sale, or delivery of electricity or natural gas
9 from nonaffiliate entities, or (iii) information
10 prohibited from disclosure by a regional transmission
11 organization to ensure the integrity of competitive
12 markets contracts relating to the purchase, sale, or
13 delivery of electricity or natural gas or (ii) the results
14 or conclusions of load forecast studies.
15 (24) Meetings of a residential health care facility
16 resident sexual assault and death review team or the
17 Executive Council under the Abuse Prevention Review Team
18 Act.
19 (25) Meetings of an independent team of experts under
20 Brian's Law.
21 (26) Meetings of a mortality review team appointed
22 under the Department of Juvenile Justice Mortality Review
23 Team Act.
24 (27) (Blank).
25 (28) Correspondence and records (i) that may not be
26 disclosed under Section 11-9 of the Illinois Public Aid
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1 Code or (ii) that pertain to appeals under Section 11-8 of
2 the Illinois Public Aid Code.
3 (29) Meetings between internal or external auditors
4 and governmental audit committees, finance committees, and
5 their equivalents, when the discussion involves internal
6 control weaknesses, identification of potential fraud risk
7 areas, known or suspected frauds, and fraud interviews
8 conducted in accordance with generally accepted auditing
9 standards of the United States of America.
10 (30) Those meetings or portions of meetings of a
11 fatality review team or the Illinois Fatality Review Team
12 Advisory Council during which a review of the death of an
13 eligible adult in which abuse or neglect is suspected,
14 alleged, or substantiated is conducted pursuant to Section
15 15 of the Adult Protective Services Act.
16 (31) Meetings and deliberations for decisions of the
17 Concealed Carry Licensing Review Board under the Firearm
18 Concealed Carry Act.
19 (32) Meetings between the Regional Transportation
20 Authority Board and its Service Boards when the discussion
21 involves review by the Regional Transportation Authority
22 Board of employment contracts under Section 28d of the
23 Metropolitan Transit Authority Act and Sections 3A.18 and
24 3B.26 of the Regional Transportation Authority Act.
25 (33) Those meetings or portions of meetings of the
26 advisory committee and peer review subcommittee created
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1 under Section 320 of the Illinois Controlled Substances
2 Act during which specific controlled substance prescriber,
3 dispenser, or patient information is discussed.
4 (34) Meetings of the Tax Increment Financing Reform
5 Task Force under Section 2505-800 of the Department of
6 Revenue Law of the Civil Administrative Code of Illinois.
7 (35) Meetings of the group established to discuss
8 Medicaid capitation rates under Section 5-30.8 of the
9 Illinois Public Aid Code.
10 (36) Those deliberations or portions of deliberations
11 for decisions of the Illinois Gaming Board in which there
12 is discussed any of the following: (i) personal,
13 commercial, financial, or other information obtained from
14 any source that is privileged, proprietary, confidential,
15 or a trade secret; or (ii) information specifically
16 exempted from the disclosure by federal or State law.
17 (37) Deliberations for decisions of the Illinois Law
18 Enforcement Training Standards Board, the Certification
19 Review Panel, and the Illinois State Police Merit Board
20 regarding certification and decertification.
21 (38) Meetings of the Ad Hoc Statewide Domestic
22 Violence Fatality Review Committee of the Illinois
23 Criminal Justice Information Authority Board that occur in
24 closed executive session under subsection (d) of Section
25 35 of the Domestic Violence Fatality Review Act.
26 (39) Meetings of the regional review teams under
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1 subsection (a) of Section 75 of the Domestic Violence
2 Fatality Review Act.
3 (40) Meetings of the Firearm Owner's Identification
4 Card Review Board under Section 10 of the Firearm Owners
5 Identification Card Act.
6 (d) Definitions. For purposes of this Section:
7 "Employee" means a person employed by a public body whose
8 relationship with the public body constitutes an
9 employer-employee relationship under the usual common law
10 rules, and who is not an independent contractor.
11 "Public office" means a position created by or under the
12 Constitution or laws of this State, the occupant of which is
13 charged with the exercise of some portion of the sovereign
14 power of this State. The term "public office" shall include
15 members of the public body, but it shall not include
16 organizational positions filled by members thereof, whether
17 established by law or by a public body itself, that exist to
18 assist the body in the conduct of its business.
19 "Quasi-adjudicative body" means an administrative body
20 charged by law or ordinance with the responsibility to conduct
21 hearings, receive evidence or testimony and make
22 determinations based thereon, but does not include local
23 electoral boards when such bodies are considering petition
24 challenges.
25 (e) Final action. No final action may be taken at a closed
26 meeting. Final action shall be preceded by a public recital of
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1 the nature of the matter being considered and other
2 information that will inform the public of the business being
3 conducted.
4 (Source: P.A. 102-237, eff. 1-1-22; 102-520, eff. 8-20-21;
5 102-558, eff. 8-20-21; 102-813, eff. 5-13-22; 103-311, eff.
6 7-28-23.)
7 Section 95. The Illinois Power Agency Act is amended by
8 changing Sections 1-5 and 1-20 as follows:
9 (20 ILCS 3855/1-5)
10 Sec. 1-5. Legislative declarations and findings. The
11 General Assembly finds and declares:
12 (1) The health, welfare, and prosperity of all
13 Illinois residents require the provision of adequate,
14 reliable, affordable, efficient, and environmentally
15 sustainable electric service at the lowest total cost over
16 time, taking into account any benefits of price stability.
17 (1.5) To provide the highest quality of life for the
18 residents of Illinois and to provide for a clean and
19 healthy environment, it is the policy of this State to
20 rapidly transition to 100% clean energy by 2050.
21 (2) (Blank).
22 (3) (Blank).
23 (4) It is necessary to improve the process of
24 procuring electricity to serve Illinois residents, to
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1 promote investment in energy efficiency and
2 demand-response measures, and to maintain and support
3 development of clean coal technologies, generation
4 resources that operate at all hours of the day and under
5 all weather conditions, zero emission facilities, and
6 renewable resources.
7 (5) Procuring a diverse electricity supply portfolio
8 will ensure the lowest total cost over time for adequate,
9 reliable, efficient, and environmentally sustainable
10 electric service.
11 (6) Including renewable resources and zero emission
12 credits from zero emission facilities in that portfolio
13 will reduce long-term direct and indirect costs to
14 consumers by decreasing environmental impacts and by
15 avoiding or delaying the need for new generation,
16 transmission, and distribution infrastructure. Developing
17 new renewable energy resources in Illinois, including
18 brownfield solar projects and community solar projects,
19 will help to diversify Illinois electricity supply, avoid
20 and reduce pollution, reduce peak demand, and enhance
21 public health and well-being of Illinois residents.
22 (7) Developing community solar projects in Illinois
23 will help to expand access to renewable energy resources
24 to more Illinois residents.
25 (8) Developing brownfield solar projects in Illinois
26 will help return blighted or contaminated land to
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1 productive use while enhancing public health and the
2 well-being of Illinois residents, including those in
3 environmental justice communities.
4 (9) Energy efficiency, demand-response measures, zero
5 emission energy, and renewable energy are resources
6 currently underused in Illinois. These resources should be
7 used, when cost effective, to reduce costs to consumers,
8 improve reliability, and improve environmental quality and
9 public health.
10 (10) The State should encourage the use of advanced
11 clean coal technologies that capture and sequester carbon
12 dioxide emissions to advance environmental protection
13 goals and to demonstrate the viability of coal and
14 coal-derived fuels in a carbon-constrained economy.
15 (10.5) The State should encourage the development of
16 interregional high voltage direct current (HVDC)
17 transmission lines that benefit Illinois. All ratepayers
18 in the State served by the regional transmission
19 organization where the HVDC converter station is
20 interconnected benefit from the long-term price stability
21 and market access provided by interregional HVDC
22 transmission facilities. The benefits to Illinois include:
23 reduction in wholesale power prices; access to lower-cost
24 markets; enabling the integration of additional renewable
25 generating units within the State through near
26 instantaneous dispatchability and the provision of
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1 ancillary services; creating good-paying union jobs in
2 Illinois; and, enhancing grid reliability and climate
3 resilience via HVDC facilities that are installed
4 underground.
5 (10.6) The health, welfare, and safety of the people
6 of the State are advanced by developing new HVDC
7 transmission lines predominantly along transportation
8 rights-of-way, with an HVDC converter station that is
9 located in the service territory of a public utility as
10 defined in Section 3-105 of the Public Utilities Act
11 serving more than 3,000,000 retail customers, and with a
12 project labor agreement as defined in Section 1-10 of this
13 Act.
14 (11) The General Assembly enacted Public Act 96-0795
15 to reform the State's purchasing processes, recognizing
16 that government procurement is susceptible to abuse if
17 structural and procedural safeguards are not in place to
18 ensure independence, insulation, oversight, and
19 transparency.
20 (12) The principles that underlie the procurement
21 reform legislation apply also in the context of power
22 purchasing.
23 (13) To ensure that the benefits of installing
24 renewable resources are available to all Illinois
25 residents and located across the State, subject to
26 appropriation, it is necessary for the Agency to provide
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1 public information and educational resources on how
2 residents can benefit from the expansion of renewable
3 energy in Illinois and participate in the Illinois Solar
4 for All Program established in Section 1-56, the
5 Adjustable Block program established in Section 1-75, the
6 job training programs established by paragraph (1) of
7 subsection (a) of Section 16-108.12 of the Public
8 Utilities Act, and the programs and resources established
9 by the Energy Transition Act.
10 (14) To ensure the State's clean energy goals are
11 timely met and that reliable clean energy is produced and
12 available when customers need it, the Agency should begin
13 to procure clean power and encourage storage, including
14 through long-term contracts. Where the comparison shows
15 that clean products can be procured at or near the cost of
16 non-renewable products, the clean products should be
17 procured. This requirement will limit the State's
18 dependence on fossil generation and reduce the potential
19 need to import fossil-fueled power.
20 The General Assembly therefore finds that it is necessary
21 to create the Illinois Power Agency and that the goals and
22 objectives of that Agency are to accomplish each of the
23 following:
24 (A) Develop electricity procurement plans to ensure
25 adequate, reliable, affordable, efficient, and
26 environmentally sustainable electric service at the lowest
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1 total cost over time, taking into account any benefits of
2 price stability, for electric utilities that on December
3 31, 2005 provided electric service to at least 100,000
4 customers in Illinois and for small multi-jurisdictional
5 electric utilities that (i) on December 31, 2005 served
6 less than 100,000 customers in Illinois and (ii) request a
7 procurement plan for their Illinois jurisdictional load.
8 The procurement plan shall be updated on an annual basis
9 and shall include renewable energy resources and,
10 beginning with the delivery year commencing June 1, 2017,
11 zero emission credits from zero emission facilities
12 sufficient to achieve the standards specified in this Act.
13 (B) Conduct the competitive procurement processes
14 identified in this Act.
15 (C) Develop electric generation and co-generation
16 facilities that use indigenous coal or renewable
17 resources, or both, financed with bonds issued by the
18 Illinois Finance Authority.
19 (D) Supply electricity from the Agency's facilities at
20 cost to one or more of the following: municipal electric
21 systems, governmental aggregators, or rural electric
22 cooperatives in Illinois.
23 (E) Ensure that the process of power procurement is
24 conducted in an ethical and transparent fashion, immune
25 from improper influence.
26 (F) Continue to review its policies and practices to
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1 determine how best to meet its mission of providing the
2 lowest cost power to the greatest number of people, at any
3 given point in time, in accordance with applicable law.
4 (G) Operate in a structurally insulated, independent,
5 and transparent fashion so that nothing impedes the
6 Agency's mission to secure power at the best prices the
7 market will bear, provided that the Agency meets all
8 applicable legal requirements.
9 (H) Implement renewable energy procurement and
10 training programs throughout the State to diversify
11 Illinois electricity supply, improve reliability, avoid
12 and reduce pollution, reduce peak demand, and enhance
13 public health and well-being of Illinois residents,
14 including low-income residents.
15 (Source: P.A. 102-662, eff. 9-15-21.)
16 (20 ILCS 3855/1-20)
17 Sec. 1-20. General powers and duties of the Agency.
18 (a) The Agency is authorized to do each of the following:
19 (1) Develop electricity procurement plans to ensure
20 adequate, reliable, affordable, efficient, and
21 environmentally sustainable electric service at the lowest
22 total cost over time, taking into account any benefits of
23 price stability, for electric utilities that on December
24 31, 2005 provided electric service to at least 100,000
25 customers in Illinois and for small multi-jurisdictional
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1 electric utilities that (A) on December 31, 2005 served
2 less than 100,000 customers in Illinois and (B) request a
3 procurement plan for their Illinois jurisdictional load.
4 Except as provided in paragraph (1.5) of this subsection
5 (a), the electricity procurement plans shall be updated on
6 an annual basis and shall include electricity generated
7 from renewable resources sufficient to achieve the
8 standards specified in this Act. Beginning with the
9 delivery year commencing June 1, 2017, develop procurement
10 plans to include zero emission credits generated from zero
11 emission facilities sufficient to achieve the standards
12 specified in this Act. Beginning with the delivery year
13 commencing on June 1, 2022, the Agency is authorized to
14 develop carbon mitigation credit procurement plans to
15 include carbon mitigation credits generated from
16 carbon-free energy resources sufficient to achieve the
17 standards specified in this Act.
18 (1.5) Develop a long-term renewable resources
19 procurement plan in accordance with subsection (c) of
20 Section 1-75 of this Act for renewable energy credits in
21 amounts sufficient to achieve the standards specified in
22 this Act for delivery years commencing June 1, 2017 and
23 for the programs and renewable energy credits specified in
24 Section 1-56 of this Act. Electricity procurement plans
25 for delivery years commencing after May 31, 2017, shall
26 not include procurement of renewable energy resources.
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1 (2) Conduct competitive procurement processes to
2 procure the supply resources identified in the electricity
3 procurement plan, pursuant to Section 16-111.5 of the
4 Public Utilities Act, and, for the delivery year
5 commencing June 1, 2017, conduct procurement processes to
6 procure zero emission credits from zero emission
7 facilities, under subsection (d-5) of Section 1-75 of this
8 Act. For the delivery year commencing June 1, 2022, the
9 Agency is authorized to conduct procurement processes to
10 procure carbon mitigation credits from carbon-free energy
11 resources, under subsection (d-10) of Section 1-75 of this
12 Act.
13 (2.5) Beginning with the procurement for the 2017
14 delivery year, conduct competitive procurement processes
15 and implement programs to procure renewable energy credits
16 identified in the long-term renewable resources
17 procurement plan developed and approved under subsection
18 (c) of Section 1-75 of this Act and Section 16-111.5 of the
19 Public Utilities Act.
20 (2.10) Oversee the procurement by electric utilities
21 that served more than 300,000 customers in this State as
22 of January 1, 2019 of renewable energy credits from new
23 renewable energy facilities to be installed, along with
24 energy storage facilities, at or adjacent to the sites of
25 electric generating facilities that burned coal as their
26 primary fuel source as of January 1, 2016 in accordance
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1 with subsection (c-5) of Section 1-75 of this Act.
2 (2.15) Oversee the procurement by electric utilities
3 of renewable energy credits from newly modernized or
4 retooled hydropower dams or dams that have been converted
5 to support hydropower generation.
6 (3) Develop electric generation and co-generation
7 facilities that use indigenous coal or renewable
8 resources, or both, financed with bonds issued by the
9 Illinois Finance Authority.
10 (4) Supply electricity from the Agency's facilities at
11 cost to one or more of the following: municipal electric
12 systems, governmental aggregators, or rural electric
13 cooperatives in Illinois.
14 (b) Except as otherwise limited by this Act, the Agency
15 has all of the powers necessary or convenient to carry out the
16 purposes and provisions of this Act, including without
17 limitation, each of the following:
18 (1) To have a corporate seal, and to alter that seal at
19 pleasure, and to use it by causing it or a facsimile to be
20 affixed or impressed or reproduced in any other manner.
21 (2) To use the services of the Illinois Finance
22 Authority necessary to carry out the Agency's purposes.
23 (3) To negotiate and enter into loan agreements and
24 other agreements with the Illinois Finance Authority.
25 (4) To obtain and employ personnel and hire
26 consultants that are necessary to fulfill the Agency's
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1 purposes, and to make expenditures for that purpose within
2 the appropriations for that purpose.
3 (5) To purchase, receive, take by grant, gift, devise,
4 bequest, or otherwise, lease, or otherwise acquire, own,
5 hold, improve, employ, use, and otherwise deal in and
6 with, real or personal property whether tangible or
7 intangible, or any interest therein, within the State.
8 (6) To acquire real or personal property, whether
9 tangible or intangible, including without limitation
10 property rights, interests in property, franchises,
11 obligations, contracts, and debt and equity securities,
12 and to do so by the exercise of the power of eminent domain
13 in accordance with Section 1-21; except that any real
14 property acquired by the exercise of the power of eminent
15 domain must be located within the State.
16 (7) To sell, convey, lease, exchange, transfer,
17 abandon, or otherwise dispose of, or mortgage, pledge, or
18 create a security interest in, any of its assets,
19 properties, or any interest therein, wherever situated.
20 (8) To purchase, take, receive, subscribe for, or
21 otherwise acquire, hold, make a tender offer for, vote,
22 employ, sell, lend, lease, exchange, transfer, or
23 otherwise dispose of, mortgage, pledge, or grant a
24 security interest in, use, and otherwise deal in and with,
25 bonds and other obligations, shares, or other securities
26 (or interests therein) issued by others, whether engaged
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1 in a similar or different business or activity.
2 (9) To make and execute agreements, contracts, and
3 other instruments necessary or convenient in the exercise
4 of the powers and functions of the Agency under this Act,
5 including contracts with any person, including personal
6 service contracts, or with any local government, State
7 agency, or other entity; and all State agencies and all
8 local governments are authorized to enter into and do all
9 things necessary to perform any such agreement, contract,
10 or other instrument with the Agency. No such agreement,
11 contract, or other instrument shall exceed 40 years.
12 (10) To lend money, invest and reinvest its funds in
13 accordance with the Public Funds Investment Act, and take
14 and hold real and personal property as security for the
15 payment of funds loaned or invested.
16 (11) To borrow money at such rate or rates of interest
17 as the Agency may determine, issue its notes, bonds, or
18 other obligations to evidence that indebtedness, and
19 secure any of its obligations by mortgage or pledge of its
20 real or personal property, machinery, equipment,
21 structures, fixtures, inventories, revenues, grants, and
22 other funds as provided or any interest therein, wherever
23 situated.
24 (12) To enter into agreements with the Illinois
25 Finance Authority to issue bonds whether or not the income
26 therefrom is exempt from federal taxation.
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1 (13) To procure insurance against any loss in
2 connection with its properties or operations in such
3 amount or amounts and from such insurers, including the
4 federal government, as it may deem necessary or desirable,
5 and to pay any premiums therefor.
6 (14) To negotiate and enter into agreements with
7 trustees or receivers appointed by United States
8 bankruptcy courts or federal district courts or in other
9 proceedings involving adjustment of debts and authorize
10 proceedings involving adjustment of debts and authorize
11 legal counsel for the Agency to appear in any such
12 proceedings.
13 (15) To file a petition under Chapter 9 of Title 11 of
14 the United States Bankruptcy Code or take other similar
15 action for the adjustment of its debts.
16 (16) To enter into management agreements for the
17 operation of any of the property or facilities owned by
18 the Agency.
19 (17) To enter into an agreement to transfer and to
20 transfer any land, facilities, fixtures, or equipment of
21 the Agency to one or more municipal electric systems,
22 governmental aggregators, or rural electric agencies or
23 cooperatives, for such consideration and upon such terms
24 as the Agency may determine to be in the best interest of
25 the residents of Illinois.
26 (18) To enter upon any lands and within any building
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1 whenever in its judgment it may be necessary for the
2 purpose of making surveys and examinations to accomplish
3 any purpose authorized by this Act.
4 (19) To maintain an office or offices at such place or
5 places in the State as it may determine.
6 (20) To request information, and to make any inquiry,
7 investigation, survey, or study that the Agency may deem
8 necessary to enable it effectively to carry out the
9 provisions of this Act.
10 (21) To accept and expend appropriations.
11 (22) To engage in any activity or operation that is
12 incidental to and in furtherance of efficient operation to
13 accomplish the Agency's purposes, including hiring
14 employees that the Director deems essential for the
15 operations of the Agency.
16 (23) To adopt, revise, amend, and repeal rules with
17 respect to its operations, properties, and facilities as
18 may be necessary or convenient to carry out the purposes
19 of this Act, subject to the provisions of the Illinois
20 Administrative Procedure Act and Sections 1-22 and 1-35 of
21 this Act.
22 (24) To establish and collect charges and fees as
23 described in this Act.
24 (25) To conduct competitive gasification feedstock
25 procurement processes to procure the feedstocks for the
26 clean coal SNG brownfield facility in accordance with the
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1 requirements of Section 1-78 of this Act.
2 (26) To review, revise, and approve sourcing
3 agreements and mediate and resolve disputes between gas
4 utilities and the clean coal SNG brownfield facility
5 pursuant to subsection (h-1) of Section 9-220 of the
6 Public Utilities Act.
7 (27) To request, review and accept proposals, execute
8 contracts, purchase renewable energy credits and otherwise
9 dedicate funds from the Illinois Power Agency Renewable
10 Energy Resources Fund to create and carry out the
11 objectives of the Illinois Solar for All Program in
12 accordance with Section 1-56 of this Act.
13 (28) To ensure Illinois residents and business benefit
14 from programs administered by the Agency and are properly
15 protected from any deceptive or misleading marketing
16 practices by participants in the Agency's programs and
17 procurements.
18 (c) In conducting the procurement of electricity or other
19 products, beginning January 1, 2022, the Agency shall not
20 procure any products or services from persons or organizations
21 that are in violation of the Displaced Energy Workers Bill of
22 Rights, as provided under the Energy Community Reinvestment
23 Act at the time of the procurement event or fail to comply the
24 labor standards established in subparagraph (Q) of paragraph
25 (1) of subsection (c) of Section 1-75.
26 (Source: P.A. 102-662, eff. 9-15-21; 103-380, eff. 1-1-24.)
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1 Section 100. The Illinois Municipal Code is amended by
2 changing Sections 11-119.1-4 and 11-119.1-10 and by adding
3 Section 11-119.1-5.5 as follows:
4 (65 ILCS 5/11-119.1-4) (from Ch. 24, par. 11-119.1-4)
5 Sec. 11-119.1-4. Municipal Power Agencies.
6 A. Any 2 or more municipalities, contiguous or
7 noncontiguous, and which operate an electric utility system,
8 may form a municipal power agency by the execution of an agency
9 agreement authorized by an ordinance adopted by the governing
10 body of each municipality. The agency agreement may state:
11 (1) that the municipal power agency is created and
12 incorporated under the provisions of this Division as a
13 body politic and corporate, municipal corporation and unit
14 of local government of the State of Illinois;
15 (2) the name of the agency and the date of its
16 establishment;
17 (3) that names of the municipalities which have
18 adopted the agency agreement and constitute the initial
19 members of the municipal power agency;
20 (4) the names and addresses of the persons initially
21 appointed in the ordinances adopting the agency agreement
22 to serve on the Board of Directors and act as the
23 representatives of the municipalities, respectively, in
24 the exercise of their powers as members;
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1 (5) the limitations, if any, upon the terms of office
2 of the directors, provided that such directors shall
3 always be selected and vacancies in their offices declared
4 and filled by ordinances adopted by the governing body of
5 the respective municipalities;
6 (6) the location by city, village or incorporated town
7 in the State of Illinois of the principal office of the
8 municipal power agency;
9 (7) provisions for the disposition, division or
10 distribution of obligations, property and assets of the
11 municipal power agency upon dissolution; and
12 (8) any other provisions for regulating the business
13 of the municipal power agency or the conduct of its
14 affairs which may be agreed to by the member
15 municipalities, consistent with this Division, including,
16 without limitation, any provisions for weighted voting
17 among the member municipalities or by the directors.
18 B. The presiding officer of the Board of Directors of any
19 municipal power agency established pursuant to this Division
20 or such other officer selected by the Board of Directors,
21 within 3 months after establishment, shall file a certified
22 copy of the agency agreement and a list of the municipalities
23 which have adopted the agreement with the recorder of deeds of
24 the county in which the principal office is located. The
25 recorder of deeds shall record this certified copy and list
26 and shall immediately transmit the certified copy and list to
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1 the Secretary of State, together with his certificate of
2 recordation. The Secretary of State shall file these documents
3 and issue his certificate of approval over his signature and
4 the Great Seal of the State. The Secretary of State shall make
5 and keep a register of municipal power agencies established
6 under this Division.
7 C. Each municipality which becomes a member of the
8 municipal power agency shall appoint a representative to serve
9 on the Board of Directors, which representative may be a
10 member of the governing body of the municipality. Each
11 appointment shall be made by the mayor, or president, subject
12 to the confirmation of the governing body. The directors so
13 appointed shall hold office for a term of 3 years, or until a
14 successor has been duly appointed and qualified, except that
15 the directors first appointed shall determine by lot at their
16 initial meeting the respective directors which shall serve for
17 a term of one, 2 or 3 years from the date of that meeting. A
18 vacancy shall be filled for the balance of the unexpired term
19 in the same manner as the original appointment.
20 The Board of Directors is the corporate authority of the
21 municipal power agency and shall exercise all the powers and
22 manage and control all of the affairs and property of the
23 agency. The Board of Directors shall have full power to pass
24 all necessary ordinances, resolutions, rules and regulations
25 for the proper management and conduct of the business of the
26 board, and for carrying into effect the objects for which the
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1 agency was established.
2 At the initial meeting of the Board of Directors to be held
3 within 30 days after the date of establishment of the
4 municipal power agency, the directors shall elect from their
5 members a presiding officer to preside over the meetings of
6 the Board of Directors and an alternative presiding officer
7 and may elect an executive board. The Board of Directors shall
8 determine and designate in the agency's bylaws the titles for
9 the presiding officers. The directors shall also elect a
10 secretary and treasurer, who need not be directors. The board
11 may select such other officers, employees and agents as deemed
12 to be necessary, who need not be directors or residents of any
13 of the municipalities which are members of the municipal power
14 agency. The board may designate appropriate titles for all
15 other officers, employees, and agents. All persons selected by
16 the board shall hold their respective offices during the
17 pleasure of the board, and give such bond as may be required by
18 the board.
19 D. The bylaws of the municipal power agency, and any
20 amendments thereto, shall be adopted by the Board of Directors
21 by a majority vote (adjusted for weighted voting, if provided
22 in the Agency Agreement) to provide the following:
23 (1) the conditions and obligations of membership, if
24 any;
25 (2) the manner and time of calling regular and special
26 meetings of the Board of Directors;
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1 (3) the procedural rules of the Board of Directors;
2 (4) the composition, powers and responsibilities of
3 any committee or executive board;
4 (5) the rights and obligations of new members,
5 conditions for the termination of membership, including a
6 formula for the determination of required termination
7 payments, if any, and the disposition of rights and
8 obligations upon termination of membership; and
9 (6) such other rules or provisions for regulating the
10 affairs of the municipal power agency as the board shall
11 determine to be necessary.
12 E. Every municipal power agency shall maintain an office
13 in the State of Illinois to be known as its principal office.
14 When a municipal power agency desires to change the location
15 of such office, it shall file with the Secretary of State a
16 certificate of change of location, stating the new address and
17 the effective date of change. Meetings of the Board of
18 Directors may be held at any place within the State of
19 Illinois, designated by the Board of Directors, after notice.
20 Unless otherwise provided by the bylaws, an act of the
21 majority of the directors present at a meeting at which a
22 quorum is present is the act of the Board of Directors.
23 F. The Board of Directors shall hold at least one meeting
24 each year for the election of officers and for the transaction
25 of any other business. Special meetings of the Board of
26 Directors may be called for any purpose upon written request
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1 to the presiding officer of the Board of Directors or
2 secretary to call the meeting. Such officer shall give notice
3 of the meeting to be held not less than 10 days and not more
4 than 60 days after receipt of such request. Unless the bylaws
5 provide for a different percentage, a quorum for a meeting of
6 the Board of Directors is a majority of all members then in
7 office. All meetings of the board shall be held in compliance
8 with the provisions of "An Act in relation to meetings",
9 approved July 11, 1957, as amended.
10 G. The agency agreement may be amended as proposed at any
11 meeting of the Board of Directors for which notice, stating
12 the purpose, shall be given to each director and, unless the
13 bylaws prescribe otherwise, such amendment shall become
14 effective when ratified by ordinances adopted by a majority of
15 the governing bodies of the member municipalities. Each
16 amendment, duly certified, shall be recorded and filed in the
17 same manner as for the original agreement.
18 H. Each member municipality shall have full power and
19 authority, subject to the provisions of its charter and laws
20 regarding local finance, to appropriate money for the payment
21 of the expenses of the municipal power agency and of its
22 representative in exercising its functions as a member of the
23 municipal power agency.
24 I. Any additional municipality which operates an electric
25 utility system may join the municipal power agency, or any
26 member municipality may withdraw therefrom consistent with the
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1 bylaws of the municipal power agency, and upon payment of any
2 termination obligations as described in subsection D upon the
3 approval by ordinance adopted by the governing body of the
4 majority of the municipalities which are then members of the
5 municipal power agency. Any new member shall agree to assume
6 its proportionate share of the outstanding obligations of the
7 municipal power agency and any member permitted to withdraw
8 shall remain obligated to make payments under any outstanding
9 contract or agreement with the municipal power agency or to
10 comply with any exit or early termination provisions set forth
11 in that contract or agreement. Any such change in membership
12 shall be recorded and filed in the same manner as for the
13 original agreement.
14 J. Any 2 or more municipal power agencies organized
15 pursuant to this Division may consolidate to form a new
16 municipal power agency when approved by ordinance adopted by
17 the governing body of each municipality which is a member of
18 the respective municipal power agency and by the execution of
19 an agency agreement as provided in this Section.
20 (Source: P.A. 96-204, eff. 1-1-10.)
21 (65 ILCS 5/11-119.1-5.5 new)
22 Sec. 11-119.1-5.5. Agency records, budgets, and quarterly
23 reports.
24 (a) A municipal power agency shall keep accurate accounts
25 and records of its assets, liabilities, revenues, and
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1 expenditures in accordance with generally accepted accounting
2 principles. Such accounts and records shall include, but are
3 not limited to, depreciation, operating and maintenance
4 expenses for all generation and transmission assets, fuel
5 costs, cost and revenue from the purchase or sale of
6 environmental compliance credits, revenue from energy,
7 capacity, and ancillary market sales, all payments received
8 from member municipalities, membership dues or other payments
9 made to trade associations or industry organizations, and
10 lobbying expenditures. Such records shall be audited on an
11 annual basis by an independent auditor using generally
12 accepted auditing standards and shall include contents as set
13 forth in Section 8-8-5, and shall be filed with the
14 Comptroller as described by Section 8-8-7.
15 (b) A municipal power agency shall, on an annual basis,
16 prepare one-year and 5-year budgets that include all revenues
17 and expenses, including, but not limited to, those categories
18 described in subsection (a). As part of each one-year budget,
19 the municipal power agency shall include a report identifying
20 and explaining any variance from the previous annual budget of
21 5% or greater in any expenditure or revenue line item. Such
22 budgets shall be provided to member municipalities no less
23 than 60 days prior to any meeting of the municipal power agency
24 during which action on the budget is or will be part of the
25 agency agenda.
26 (c) The municipal power agency shall post, on a publicly
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1 available website, all one-year and 5-year budgets required
2 under subsection (b) and the annual audited financial
3 statements required under subsection (a).
4 (d) The municipal power agency shall make available, upon
5 request to any of its member municipalities, access to all
6 municipal power agency all records and accounts and all
7 financial information relating to ownership and operation of
8 agency assets and the generation, procurement, and delivery of
9 electricity to which the agency has access, including, but not
10 limited to, unit scheduling information, market revenue and
11 off-system sales data, and fuel and other variable cost
12 information. Such information shall be provided in a timely
13 manner and through reasonable means, and members shall be
14 permitted to make copies of any documents retained solely by
15 the agency. Such access shall be provided without regard to
16 any nondisclosure agreement that has been or may be adopted by
17 the municipal power agency.
18 (e) The municipal power agency shall prepare, on a
19 quarterly basis, a report to its member municipalities
20 describing all expenditures made for the purpose of lobbying,
21 as both terms are defined by Section 2 of the Lobbyist
22 Registration Act, and a brief summary of the topics and
23 positions on which lobbying activities were undertaken. Where
24 the municipal power agency is a member of an organization or
25 trade association that expends some or all of membership dues
26 on lobbying activities, the municipal power agency shall
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1 include in this report the amount of those membership dues,
2 what proportion of those dues were spent on lobbying
3 activities, and the topics and positions on which lobbying
4 activities were undertaken by the organization or trade
5 association of which the municipal power agency is a member.
6 (65 ILCS 5/11-119.1-10) (from Ch. 24, par. 11-119.1-10)
7 Sec. 11-119.1-10. Exercise of powers. A municipal power
8 agency may exercise any and all of the powers enumerated in
9 this Division, except the power of eminent domain, without the
10 consent and approval of the Illinois Commerce Commission. The
11 exercise of the power of eminent domain by a municipal power
12 agency shall be subject to the consent and approval of the
13 Illinois Commerce Commission in the same manner and to the
14 same extent as public utilities under the Public Utilities
15 Act, including the issuance of a certificate of public
16 convenience and necessity as provided for in Section 8-406 of
17 that Act. During the consideration of any petition for
18 authority to exercise the power of eminent domain the Illinois
19 Commerce Commission shall evaluate and give due consideration
20 to whether the project for which eminent domain is sought is
21 part of the preferred portfolio as described in subsection (d)
22 of Section 15 of the Municipal and Cooperative Electric
23 Utility Planning and Transparency Act, or least cost plans for
24 procuring renewable resources as described in subsections (f)
25 and (g) of Section 20 of the Municipal and Cooperative
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1 Electric Utility Planning and Transparency Act and to the
2 impact of the acquisition on farmlands in the State with the
3 goal of preserving the land to the fullest extent reasonably
4 possible.
5 (Source: P.A. 90-416, eff. 1-1-98.)
6 Section 105. The Public Utilities Act is amended by
7 changing Sections 3-105, 8-103B, 16-107.5, 16-111.5, 16-115A,
8 16-115D, and 17-500 and by adding Section 16-107.8 as follows:
9 (220 ILCS 5/3-105) (from Ch. 111 2/3, par. 3-105)
10 Sec. 3-105. Public utility.
11 (a) "Public utility" means and includes, except where
12 otherwise expressly provided in this Section, every
13 corporation, company, limited liability company, association,
14 joint stock company or association, firm, partnership or
15 individual, their lessees, trustees, or receivers appointed by
16 any court whatsoever now or hereafter that owns, controls,
17 operates or manages, within this State, directly or
18 indirectly, for public use, any plant, equipment or property
19 used or to be used for or in connection with, or owns or
20 controls or seeks Commission approval to own or control any
21 franchise, license, permit or right to engage in:
22 (1) the production, storage, transmission, sale,
23 delivery or furnishing of heat, cold, power, electricity,
24 water, or light, except when used solely for
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1 communications purposes;
2 (2) the disposal of sewerage; or
3 (3) the conveyance of oil or gas by pipe line.
4 (b) "Public utility" does not include, however:
5 (1) public utilities that are owned and operated by
6 any political subdivision, public institution of higher
7 education or municipal corporation of this State, or
8 public utilities that are owned by such political
9 subdivision, public institution of higher education, or
10 municipal corporation and operated by any of its lessees
11 or operating agents;
12 (2) water companies which are purely mutual concerns,
13 having no rates or charges for services, but paying the
14 operating expenses by assessment upon the members of such
15 a company and no other person;
16 (3) electric cooperatives as defined in Section 3-119;
17 (4) the following natural gas cooperatives:
18 (A) residential natural gas cooperatives that are
19 not-for-profit corporations established for the
20 purpose of administering and operating, on a
21 cooperative basis, the furnishing of natural gas to
22 residences for the benefit of their members who are
23 residential consumers of natural gas. For entities
24 qualifying as residential natural gas cooperatives and
25 recognized by the Illinois Commerce Commission as
26 such, the State shall guarantee legally binding
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1 contracts entered into by residential natural gas
2 cooperatives for the express purpose of acquiring
3 natural gas supplies for their members. The Illinois
4 Commerce Commission shall establish rules and
5 regulations providing for such guarantees. The total
6 liability of the State in providing all such
7 guarantees shall not at any time exceed $1,000,000,
8 nor shall the State provide such a guarantee to a
9 residential natural gas cooperative for more than 3
10 consecutive years; and
11 (B) natural gas cooperatives that are
12 not-for-profit corporations operated for the purpose
13 of administering, on a cooperative basis, the
14 furnishing of natural gas for the benefit of their
15 members and that, prior to 90 days after the effective
16 date of this amendatory Act of the 94th General
17 Assembly, either had acquired or had entered into an
18 asset purchase agreement to acquire all or
19 substantially all of the operating assets of a public
20 utility or natural gas cooperative with the intention
21 of operating those assets as a natural gas
22 cooperative;
23 (5) sewage disposal companies which provide sewage
24 disposal services on a mutual basis without establishing
25 rates or charges for services, but paying the operating
26 expenses by assessment upon the members of the company and
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1 no others;
2 (6) (blank);
3 (7) cogeneration facilities, small power production
4 facilities, and other qualifying facilities, as defined in
5 the Public Utility Regulatory Policies Act and regulations
6 promulgated thereunder, except to the extent State
7 regulatory jurisdiction and action is required or
8 authorized by federal law, regulations, regulatory
9 decisions or the decisions of federal or State courts of
10 competent jurisdiction;
11 (8) the ownership or operation of a facility that
12 sells compressed natural gas at retail to the public for
13 use only as a motor vehicle fuel and the selling of
14 compressed natural gas at retail to the public for use
15 only as a motor vehicle fuel;
16 (9) alternative retail electric suppliers as defined
17 in Article XVI; and
18 (10) the Illinois Power Agency.
19 (c) An entity that furnishes the service of charging
20 electric vehicles does not and shall not be deemed to sell
21 electricity and is not and shall not be deemed a public utility
22 notwithstanding the basis on which the service is provided or
23 billed. If, however, the entity is otherwise deemed a public
24 utility under this Act, or is otherwise subject to regulation
25 under this Act, then that entity is not exempt from and remains
26 subject to the otherwise applicable provisions of this Act.
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1 The installation, maintenance, and repair of an electric
2 vehicle charging station shall comply with the requirements of
3 subsection (a) of Section 16-128 and Section 16-128A of this
4 Act.
5 For purposes of this subsection, the term "electric
6 vehicles" has the meaning ascribed to that term in Section 10
7 of the Electric Vehicle Act.
8 (Source: P.A. 97-1128, eff. 8-28-12.)
9 (220 ILCS 5/8-103B)
10 Sec. 8-103B. Energy efficiency and demand-response
11 measures.
12 (a) It is the policy of the State that electric utilities
13 are required to use cost-effective energy efficiency and
14 demand-response measures to reduce delivery load. Requiring
15 investment in cost-effective energy efficiency and
16 demand-response measures will reduce direct and indirect costs
17 to consumers by decreasing environmental impacts and by
18 avoiding or delaying the need for new generation,
19 transmission, and distribution infrastructure. It serves the
20 public interest to allow electric utilities to recover costs
21 for reasonably and prudently incurred expenditures for energy
22 efficiency and demand-response measures. As used in this
23 Section, "cost-effective" means that the measures satisfy the
24 total resource cost test. The low-income measures described in
25 subsection (c) of this Section shall not be required to meet
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1 the total resource cost test. For purposes of this Section,
2 the terms "energy-efficiency", "demand-response", "electric
3 utility", and "total resource cost test" have the meanings set
4 forth in the Illinois Power Agency Act. "Black, indigenous,
5 and people of color" and "BIPOC" means people who are members
6 of the groups described in subparagraphs (a) through (e) of
7 paragraph (A) of subsection (1) of Section 2 of the Business
8 Enterprise for Minorities, Women, and Persons with
9 Disabilities Act.
10 (a-5) This Section applies to electric utilities serving
11 more than 500,000 retail customers in the State for those
12 multi-year plans commencing after December 31, 2017.
13 (b) For purposes of this Section, through calendar year
14 2025, electric utilities subject to this Section that serve
15 more than 3,000,000 retail customers in the State shall be
16 deemed to have achieved a cumulative persisting annual savings
17 of 6.6% from energy efficiency measures and programs
18 implemented during the period beginning January 1, 2012 and
19 ending December 31, 2017, which percent is based on the deemed
20 average weather normalized sales of electric power and energy
21 during calendar years 2014, 2015, and 2016 of 88,000,000 MWhs.
22 For the purposes of this subsection (b) and subsection (b-5),
23 the 88,000,000 MWhs of deemed electric power and energy sales
24 shall be reduced by the number of MWhs equal to the sum of the
25 annual consumption of customers that have opted out of
26 subsections (a) through (j) of this Section under paragraph
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1 (1) of subsection (l) of this Section, as averaged across the
2 calendar years 2014, 2015, and 2016. After 2017, the deemed
3 value of cumulative persisting annual savings from energy
4 efficiency measures and programs implemented during the period
5 beginning January 1, 2012 and ending December 31, 2017, shall
6 be reduced each year, as follows, and the applicable value
7 shall be applied to and count toward the utility's achievement
8 of the cumulative persisting annual savings goals set forth in
9 subsection (b-5):
10 (1) 5.8% deemed cumulative persisting annual savings
11 for the year ending December 31, 2018;
12 (2) 5.2% deemed cumulative persisting annual savings
13 for the year ending December 31, 2019;
14 (3) 4.5% deemed cumulative persisting annual savings
15 for the year ending December 31, 2020;
16 (4) 4.0% deemed cumulative persisting annual savings
17 for the year ending December 31, 2021;
18 (5) 3.5% deemed cumulative persisting annual savings
19 for the year ending December 31, 2022;
20 (6) 3.1% deemed cumulative persisting annual savings
21 for the year ending December 31, 2023;
22 (7) 2.8% deemed cumulative persisting annual savings
23 for the year ending December 31, 2024; and
24 (8) 2.5% deemed cumulative persisting annual savings
25 for the year ending December 31, 2025. ;
26 (9) 2.3% deemed cumulative persisting annual savings
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1 for the year ending December 31, 2026;
2 (10) 2.1% deemed cumulative persisting annual savings
3 for the year ending December 31, 2027;
4 (11) 1.8% deemed cumulative persisting annual savings
5 for the year ending December 31, 2028;
6 (12) 1.7% deemed cumulative persisting annual savings
7 for the year ending December 31, 2029;
8 (13) 1.5% deemed cumulative persisting annual savings
9 for the year ending December 31, 2030;
10 (14) 1.3% deemed cumulative persisting annual savings
11 for the year ending December 31, 2031;
12 (15) 1.1% deemed cumulative persisting annual savings
13 for the year ending December 31, 2032;
14 (16) 0.9% deemed cumulative persisting annual savings
15 for the year ending December 31, 2033;
16 (17) 0.7% deemed cumulative persisting annual savings
17 for the year ending December 31, 2034;
18 (18) 0.5% deemed cumulative persisting annual savings
19 for the year ending December 31, 2035;
20 (19) 0.4% deemed cumulative persisting annual savings
21 for the year ending December 31, 2036;
22 (20) 0.3% deemed cumulative persisting annual savings
23 for the year ending December 31, 2037;
24 (21) 0.2% deemed cumulative persisting annual savings
25 for the year ending December 31, 2038;
26 (22) 0.1% deemed cumulative persisting annual savings
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1 for the year ending December 31, 2039; and
2 (23) 0.0% deemed cumulative persisting annual savings
3 for the year ending December 31, 2040 and all subsequent
4 years.
5 For purposes of this Section, "cumulative persisting
6 annual savings" means the total electric energy savings in a
7 given year from measures installed in that year or in previous
8 years, but no earlier than January 1, 2012, that are still
9 operational and providing savings in that year because the
10 measures have not yet reached the end of their useful lives.
11 (b-5) Beginning in 2018, through calendar year 2025,
12 electric utilities subject to this Section that serve more
13 than 3,000,000 retail customers in the State shall achieve the
14 following cumulative persisting annual savings goals, as
15 modified by subsection (f) of this Section and as compared to
16 the deemed baseline of 88,000,000 MWhs of electric power and
17 energy sales set forth in subsection (b), as reduced by the
18 number of MWhs equal to the sum of the annual consumption of
19 customers that have opted out of subsections (a) through (j)
20 of this Section under paragraph (1) of subsection (l) of this
21 Section as averaged across the calendar years 2014, 2015, and
22 2016, through the implementation of energy efficiency measures
23 during the applicable year and in prior years, but no earlier
24 than January 1, 2012:
25 (1) 7.8% cumulative persisting annual savings for the
26 year ending December 31, 2018;
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1 (2) 9.1% cumulative persisting annual savings for the
2 year ending December 31, 2019;
3 (3) 10.4% cumulative persisting annual savings for the
4 year ending December 31, 2020;
5 (4) 11.8% cumulative persisting annual savings for the
6 year ending December 31, 2021;
7 (5) 13.1% cumulative persisting annual savings for the
8 year ending December 31, 2022;
9 (6) 14.4% cumulative persisting annual savings for the
10 year ending December 31, 2023;
11 (7) 15.7% cumulative persisting annual savings for the
12 year ending December 31, 2024; and
13 (8) 17% cumulative persisting annual savings for the
14 year ending December 31, 2025. ;
15 (9) 17.9% cumulative persisting annual savings for the
16 year ending December 31, 2026;
17 (10) 18.8% cumulative persisting annual savings for
18 the year ending December 31, 2027;
19 (11) 19.7% cumulative persisting annual savings for
20 the year ending December 31, 2028;
21 (12) 20.6% cumulative persisting annual savings for
22 the year ending December 31, 2029; and
23 (13) 21.5% cumulative persisting annual savings for
24 the year ending December 31, 2030.
25 No later than December 31, 2021, the Illinois Commerce
26 Commission shall establish additional cumulative persisting
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1 annual savings goals for the years 2031 through 2035. No later
2 than December 31, 2024, the Illinois Commerce Commission shall
3 establish additional cumulative persisting annual savings
4 goals for the years 2036 through 2040. The Commission shall
5 also establish additional cumulative persisting annual savings
6 goals every 5 years thereafter to ensure that utilities always
7 have goals that extend at least 11 years into the future. The
8 cumulative persisting annual savings goals beyond the year
9 2030 shall increase by 0.9 percentage points per year, absent
10 a Commission decision to initiate a proceeding to consider
11 establishing goals that increase by more or less than that
12 amount. Such a proceeding must be conducted in accordance with
13 the procedures described in subsection (f) of this Section. If
14 such a proceeding is initiated, the cumulative persisting
15 annual savings goals established by the Commission through
16 that proceeding shall reflect the Commission's best estimate
17 of the maximum amount of additional savings that are forecast
18 to be cost-effectively achievable unless such best estimates
19 would result in goals that represent less than 0.5 percentage
20 point annual increases in total cumulative persisting annual
21 savings. The Commission may only establish goals that
22 represent less than 0.5 percentage point annual increases in
23 cumulative persisting annual savings if it can demonstrate,
24 based on clear and convincing evidence and through independent
25 analysis, that 0.5 percentage point increases are not
26 cost-effectively achievable. The Commission shall inform its
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1 decision based on an energy efficiency potential study that
2 conforms to the requirements of this Section.
3 (b-10) For purposes of this Section, through calendar year
4 2025, electric utilities subject to this Section that serve
5 less than 3,000,000 retail customers but more than 500,000
6 retail customers in the State shall be deemed to have achieved
7 a cumulative persisting annual savings of 6.6% from energy
8 efficiency measures and programs implemented during the period
9 beginning January 1, 2012 and ending December 31, 2017, which
10 is based on the deemed average weather normalized sales of
11 electric power and energy during calendar years 2014, 2015,
12 and 2016 of 36,900,000 MWhs. For the purposes of this
13 subsection (b-10) and subsection (b-15), the 36,900,000 MWhs
14 of deemed electric power and energy sales shall be reduced by
15 the number of MWhs equal to the sum of the annual consumption
16 of customers that have opted out of subsections (a) through
17 (j) of this Section under paragraph (1) of subsection (l) of
18 this Section, as averaged across the calendar years 2014,
19 2015, and 2016. After 2017, the deemed value of cumulative
20 persisting annual savings from energy efficiency measures and
21 programs implemented during the period beginning January 1,
22 2012 and ending December 31, 2017, shall be reduced each year,
23 as follows, and the applicable value shall be applied to and
24 count toward the utility's achievement of the cumulative
25 persisting annual savings goals set forth in subsection
26 (b-15):
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1 (1) 5.8% deemed cumulative persisting annual savings
2 for the year ending December 31, 2018;
3 (2) 5.2% deemed cumulative persisting annual savings
4 for the year ending December 31, 2019;
5 (3) 4.5% deemed cumulative persisting annual savings
6 for the year ending December 31, 2020;
7 (4) 4.0% deemed cumulative persisting annual savings
8 for the year ending December 31, 2021;
9 (5) 3.5% deemed cumulative persisting annual savings
10 for the year ending December 31, 2022;
11 (6) 3.1% deemed cumulative persisting annual savings
12 for the year ending December 31, 2023;
13 (7) 2.8% deemed cumulative persisting annual savings
14 for the year ending December 31, 2024; and
15 (8) 2.5% deemed cumulative persisting annual savings
16 for the year ending December 31, 2025. ;
17 (9) 2.3% deemed cumulative persisting annual savings
18 for the year ending December 31, 2026;
19 (10) 2.1% deemed cumulative persisting annual savings
20 for the year ending December 31, 2027;
21 (11) 1.8% deemed cumulative persisting annual savings
22 for the year ending December 31, 2028;
23 (12) 1.7% deemed cumulative persisting annual savings
24 for the year ending December 31, 2029;
25 (13) 1.5% deemed cumulative persisting annual savings
26 for the year ending December 31, 2030;
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1 (14) 1.3% deemed cumulative persisting annual savings
2 for the year ending December 31, 2031;
3 (15) 1.1% deemed cumulative persisting annual savings
4 for the year ending December 31, 2032;
5 (16) 0.9% deemed cumulative persisting annual savings
6 for the year ending December 31, 2033;
7 (17) 0.7% deemed cumulative persisting annual savings
8 for the year ending December 31, 2034;
9 (18) 0.5% deemed cumulative persisting annual savings
10 for the year ending December 31, 2035;
11 (19) 0.4% deemed cumulative persisting annual savings
12 for the year ending December 31, 2036;
13 (20) 0.3% deemed cumulative persisting annual savings
14 for the year ending December 31, 2037;
15 (21) 0.2% deemed cumulative persisting annual savings
16 for the year ending December 31, 2038;
17 (22) 0.1% deemed cumulative persisting annual savings
18 for the year ending December 31, 2039; and
19 (23) 0.0% deemed cumulative persisting annual savings
20 for the year ending December 31, 2040 and all subsequent
21 years.
22 (b-15) Beginning in 2018, electric utilities subject to
23 this Section that serve less than 3,000,000 retail customers
24 but more than 500,000 retail customers in the State shall
25 achieve the following cumulative persisting annual savings
26 goals, as modified by subsection (b-20) and subsection (f) of
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1 this Section and as compared to the deemed baseline as reduced
2 by the number of MWhs equal to the sum of the annual
3 consumption of customers that have opted out of subsections
4 (a) through (j) of this Section under paragraph (1) of
5 subsection (l) of this Section as averaged across the calendar
6 years 2014, 2015, and 2016, through the implementation of
7 energy efficiency measures during the applicable year and in
8 prior years, but no earlier than January 1, 2012:
9 (1) 7.4% cumulative persisting annual savings for the
10 year ending December 31, 2018;
11 (2) 8.2% cumulative persisting annual savings for the
12 year ending December 31, 2019;
13 (3) 9.0% cumulative persisting annual savings for the
14 year ending December 31, 2020;
15 (4) 9.8% cumulative persisting annual savings for the
16 year ending December 31, 2021;
17 (5) 10.6% cumulative persisting annual savings for the
18 year ending December 31, 2022;
19 (6) 11.4% cumulative persisting annual savings for the
20 year ending December 31, 2023;
21 (7) 12.2% cumulative persisting annual savings for the
22 year ending December 31, 2024;
23 (8) 13% cumulative persisting annual savings for the
24 year ending December 31, 2025;
25 (9) 13.6% cumulative persisting annual savings for the
26 year ending December 31, 2026;
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1 (10) 14.2% cumulative persisting annual savings for
2 the year ending December 31, 2027;
3 (11) 14.8% cumulative persisting annual savings for
4 the year ending December 31, 2028;
5 (12) 15.4% cumulative persisting annual savings for
6 the year ending December 31, 2029; and
7 (13) 16% cumulative persisting annual savings for the
8 year ending December 31, 2030.
9 No later than December 31, 2021, the Illinois Commerce
10 Commission shall establish additional cumulative persisting
11 annual savings goals for the years 2031 through 2035. No later
12 than December 31, 2024, the Illinois Commerce Commission shall
13 establish additional cumulative persisting annual savings
14 goals for the years 2036 through 2040. The Commission shall
15 also establish additional cumulative persisting annual savings
16 goals every 5 years thereafter to ensure that utilities always
17 have goals that extend at least 11 years into the future. The
18 cumulative persisting annual savings goals beyond the year
19 2030 shall increase by 0.9 0.6 percentage points per year,
20 absent a Commission decision to initiate a proceeding to
21 consider establishing goals that increase by more or less than
22 that amount. Such a proceeding must be conducted in accordance
23 with the procedures described in subsection (f) of this
24 Section. If such a proceeding is initiated, the cumulative
25 persisting annual savings goals established by the Commission
26 through that proceeding shall reflect the Commission's best
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1 estimate of the maximum amount of additional savings that are
2 forecast to be cost-effectively achievable unless such best
3 estimates would result in goals that represent less than 0.5
4 0.4 percentage point annual increases in total cumulative
5 persisting annual savings. The Commission may only establish
6 goals that represent less than 0.5 0.4 percentage point annual
7 increases in cumulative persisting annual savings if it can
8 demonstrate, based on clear and convincing evidence and
9 through independent analysis, that 0.5 0.4 percentage point
10 increases are not cost-effectively achievable. The Commission
11 shall inform its decision based on an energy efficiency
12 potential study that conforms to the requirements of this
13 Section.
14 (b-16) Beginning in 2026, and in every subsequent year,
15 each electric utility subject to this Section shall achieve
16 incremental annual savings equal to 2.25% of the utility's
17 average annual electricity sales in the second, third, and
18 fourth years prior to the start of each applicable multi-year
19 energy efficiency planning period referenced in subsection
20 (f), with an average savings life of at least 13 years. For the
21 purposes of this Section, "incremental annual savings" means
22 the total electric savings from all measures installed in a
23 calendar year that will be realized within 12 months of each
24 measure's installation. In no event can more than one-fifth of
25 the incremental annual savings counted towards a utility's
26 annual savings goal in any given year be derived from
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1 efficiency measures with average savings lives of less than 5
2 years.
3 (b-20) Each electric utility subject to this Section may
4 include cost-effective voltage optimization measures in its
5 plans submitted under subsections (f) and (g) of this Section,
6 and the costs incurred by a utility to implement the measures
7 under a Commission-approved plan shall be recovered under the
8 provisions of Article IX or Section 16-108.5 of this Act. For
9 purposes of this Section, the measure life of voltage
10 optimization measures shall be 15 years. The measure life
11 period is independent of the depreciation rate of the voltage
12 optimization assets deployed. Utilities may claim savings from
13 voltage optimization on circuits for more than 15 years if
14 they can demonstrate that they have made additional
15 investments necessary to enable voltage optimization savings
16 to continue beyond 15 years. Such demonstrations must be
17 subject to the review of independent evaluation.
18 Within 270 days after June 1, 2017 (the effective date of
19 Public Act 99-906), an electric utility that serves less than
20 3,000,000 retail customers but more than 500,000 retail
21 customers in the State shall file a plan with the Commission
22 that identifies the cost-effective voltage optimization
23 investment the electric utility plans to undertake through
24 December 31, 2024. The Commission, after notice and hearing,
25 shall approve or approve with modification the plan within 120
26 days after the plan's filing and, in the order approving or
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1 approving with modification the plan, the Commission shall
2 adjust the applicable cumulative persisting annual savings
3 goals set forth in subsection (b-15) to reflect any amount of
4 cost-effective energy savings approved by the Commission that
5 is greater than or less than the following cumulative
6 persisting annual savings values attributable to voltage
7 optimization for the applicable year:
8 (1) 0.0% of cumulative persisting annual savings for
9 the year ending December 31, 2018;
10 (2) 0.17% of cumulative persisting annual savings for
11 the year ending December 31, 2019;
12 (3) 0.17% of cumulative persisting annual savings for
13 the year ending December 31, 2020;
14 (4) 0.33% of cumulative persisting annual savings for
15 the year ending December 31, 2021;
16 (5) 0.5% of cumulative persisting annual savings for
17 the year ending December 31, 2022;
18 (6) 0.67% of cumulative persisting annual savings for
19 the year ending December 31, 2023;
20 (7) 0.83% of cumulative persisting annual savings for
21 the year ending December 31, 2024; and
22 (8) 1.0% of cumulative persisting annual savings for
23 the year ending December 31, 2025 and all subsequent
24 years.
25 (b-25) In the event an electric utility jointly offers an
26 energy efficiency measure or program with a gas utility under
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1 plans approved under this Section and Section 8-104 of this
2 Act, the electric utility may continue offering the program,
3 including the gas energy efficiency measures, in the event the
4 gas utility discontinues funding the program. In that event,
5 the energy savings value associated with such other fuels
6 shall be converted to electric energy savings on an equivalent
7 Btu basis for the premises. However, the electric utility
8 shall prioritize programs for low-income residential customers
9 to the extent practicable. An electric utility may recover the
10 costs of offering the gas energy efficiency measures under
11 this subsection (b-25).
12 For those energy efficiency measures or programs that save
13 both electricity and other fuels but are not jointly offered
14 with a gas utility under plans approved under this Section and
15 Section 8-104 or not offered with an affiliated gas utility
16 under paragraph (6) of subsection (f) of Section 8-104 of this
17 Act, the electric utility may count savings of fuels other
18 than electricity toward the achievement of its annual savings
19 goal, and the energy savings value associated with such other
20 fuels shall be converted to electric energy savings on an
21 equivalent Btu basis at the premises.
22 In no event shall more than 10% of each year's applicable
23 annual total savings requirement as defined in paragraph (7.5)
24 of subsection (g) of this Section, or more than 10% of each
25 year's incremental annual savings as defined in subsection
26 (b-16) be met through savings of fuels other than electricity.
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1 (b-27) Beginning in 2022, an electric utility may offer
2 and promote measures that electrify space heating, water
3 heating, cooling, drying, cooking, industrial processes, and
4 other building and industrial end uses that would otherwise be
5 served by combustion of fossil fuel at the premises, provided
6 that the electrification measures reduce total energy
7 consumption at the premises. The electric utility may count
8 the reduction in energy consumption at the premises toward
9 achievement of its annual savings goals. The reduction in
10 energy consumption at the premises shall be calculated as the
11 difference between: (A) the reduction in Btu consumption of
12 fossil fuels as a result of electrification, converted to
13 kilowatt-hour equivalents by dividing by 3,412 Btus per
14 kilowatt hour; and (B) the increase in kilowatt hours of
15 electricity consumption resulting from the displacement of
16 fossil fuel consumption as a result of electrification. An
17 electric utility may recover the costs of offering and
18 promoting electrification measures under this subsection
19 (b-27). At least 40% of all such costs must be for supporting
20 installation of electrification measures in low income
21 housing.
22 In no event shall electrification savings counted toward
23 each year's applicable annual total savings requirement, as
24 defined in paragraph (7.5) of subsection (g) of this Section,
25 be greater than:
26 (1) 5% per year for each year from 2022 through 2025;
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1 (2) 10% per year for each year from 2026 through 2029;
2 and
3 (3) 15% per year for 2030 and all subsequent years.
4 In addition, a minimum of 25% of all electrification savings
5 counted toward a utility's applicable annual total savings
6 requirement must be from electrification of end uses in
7 low-income housing. The limitations on electrification savings
8 that may be counted toward a utility's annual savings goals
9 are separate from and in addition to the subsection (b-25)
10 limitations governing the counting of the other fuel savings
11 resulting from efficiency measures and programs.
12 As part of the annual informational filing to the
13 Commission that is required under paragraph (9) of subsection
14 (g) of this Section, each utility shall identify the specific
15 electrification measures offered under this subsection (b-27);
16 the quantity of each electrification measure that was
17 installed by its customers; the average total cost, average
18 utility cost, average reduction in fossil fuel consumption,
19 and average increase in electricity consumption associated
20 with each electrification measure; the portion of
21 installations of each electrification measure that were in
22 low-income single-family housing, low-income multifamily
23 housing, non-low-income single-family housing, non-low-income
24 multifamily housing, commercial buildings, and industrial
25 facilities; and the quantity of savings associated with each
26 measure category in each customer category that are being
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1 counted toward the utility's applicable annual total savings
2 requirement or the utility's incremental annual savings as
3 defined in subsection (b-16). Prior to installing an
4 electrification measure, the utility shall provide a customer
5 with an estimate of the impact of the new measure on the
6 customer's average monthly electric bill and total annual
7 energy expenses.
8 (c) Electric utilities shall be responsible for overseeing
9 the design, development, and filing of energy efficiency plans
10 with the Commission and may, as part of that implementation,
11 outsource various aspects of program development and
12 implementation. A minimum of 10%, for electric utilities that
13 serve more than 3,000,000 retail customers in the State, and a
14 minimum of 7%, for electric utilities that serve less than
15 3,000,000 retail customers but more than 500,000 retail
16 customers in the State, of the utility's entire portfolio
17 funding level for a given year shall be used to procure
18 cost-effective energy efficiency measures from units of local
19 government, municipal corporations, school districts, public
20 housing, and community college districts, provided that a
21 minimum percentage of available funds shall be used to procure
22 energy efficiency from public housing, which percentage shall
23 be equal to public housing's share of public building energy
24 consumption.
25 The utilities shall also implement energy efficiency
26 measures targeted at low-income households, which, for
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1 purposes of this Section, shall be defined as households at or
2 below 80% of area median income, and expenditures to implement
3 the measures shall be no less than $1,000,000 $40,000,000 per
4 year for electric utilities that serve more than 3,000,000
5 retail customers in the State and no less than $30,000
6 $13,000,000 per year for electric utilities that serve less
7 than 3,000,000 retail customers but more than 500,000 retail
8 customers in the State. The ratio of spending on efficiency
9 programs targeted at low-income multifamily buildings to
10 spending on efficiency programs targeted at low-income
11 single-family buildings shall be designed to achieve levels of
12 savings from each building type that are approximately
13 proportional to the magnitude of cost-effective lifetime
14 savings potential in each building type. Investment in
15 low-income whole-building weatherization programs shall
16 constitute a minimum of 80% of a utility's total budget
17 specifically dedicated to serving low-income customers.
18 The utilities shall work to bundle low-income energy
19 efficiency offerings with other programs that serve low-income
20 households to maximize the benefits going to these households.
21 The utilities shall market and implement low-income energy
22 efficiency programs in coordination with low-income assistance
23 programs, the Illinois Solar for All Program, and
24 weatherization whenever practicable. The program implementer
25 shall walk the customer through the enrollment process for any
26 programs for which the customer is eligible. The utilities
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1 shall also pilot targeting customers with high arrearages,
2 high energy intensity (ratio of energy usage divided by home
3 or unit square footage), or energy assistance programs with
4 energy efficiency offerings, and then track reduction in
5 arrearages as a result of the targeting. This targeting and
6 bundling of low-income energy programs shall be offered to
7 both low-income single-family and multifamily customers
8 (owners and residents).
9 The utilities shall invest in health and safety measures
10 appropriate and necessary for comprehensively weatherizing a
11 home or multifamily building, and shall implement a health and
12 safety fund of at least 15% of the total income-qualified
13 weatherization budget that shall be used for the purpose of
14 making grants for technical assistance, construction,
15 reconstruction, improvement, or repair of buildings to
16 facilitate their participation in the energy efficiency
17 programs targeted at low-income single-family and multifamily
18 households. These funds may also be used for the purpose of
19 making grants for technical assistance, construction,
20 reconstruction, improvement, or repair of the following
21 buildings to facilitate their participation in the energy
22 efficiency programs created by this Section: (1) buildings
23 that are owned or operated by registered 501(c)(3) public
24 charities; and (2) day care centers, day care homes, or group
25 day care homes, as defined under 89 Ill. Adm. Code Part 406,
26 407, or 408, respectively.
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1 Each electric utility shall assess opportunities to
2 implement cost-effective energy efficiency measures and
3 programs through a public housing authority or authorities
4 located in its service territory. If such opportunities are
5 identified, the utility shall propose such measures and
6 programs to address the opportunities. Expenditures to address
7 such opportunities shall be credited toward the minimum
8 procurement and expenditure requirements set forth in this
9 subsection (c).
10 Implementation of energy efficiency measures and programs
11 targeted at low-income households should be contracted, when
12 it is practicable, to independent third parties that have
13 demonstrated capabilities to serve such households, with a
14 preference for not-for-profit entities and government agencies
15 that have existing relationships with or experience serving
16 low-income communities in the State.
17 Each electric utility shall develop and implement
18 reporting procedures that address and assist in determining
19 the amount of energy savings that can be applied to the
20 low-income procurement and expenditure requirements set forth
21 in this subsection (c). Each electric utility shall also track
22 the types and quantities or volumes of insulation and air
23 sealing materials, and their associated energy saving
24 benefits, installed in energy efficiency programs targeted at
25 low-income single-family and multifamily households.
26 The electric utilities shall participate in a low-income
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1 energy efficiency accountability committee ("the committee"),
2 which will directly inform the design, implementation, and
3 evaluation of the low-income and public-housing energy
4 efficiency programs. The committee shall be comprised of the
5 electric utilities subject to the requirements of this
6 Section, the gas utilities subject to the requirements of
7 Section 8-104 of this Act, the utilities' low-income energy
8 efficiency implementation contractors, nonprofit
9 organizations, community action agencies, advocacy groups,
10 State and local governmental agencies, public-housing
11 organizations, and representatives of community-based
12 organizations, especially those living in or working with
13 environmental justice communities and BIPOC communities. The
14 committee shall be composed of 2 geographically differentiated
15 subcommittees: one for stakeholders in northern Illinois and
16 one for stakeholders in central and southern Illinois. The
17 subcommittees shall meet together at least twice per year.
18 There shall be one statewide leadership committee led by
19 and composed of community-based organizations that are
20 representative of BIPOC and environmental justice communities
21 and that includes equitable representation from BIPOC
22 communities. The leadership committee shall be composed of an
23 equal number of representatives from the 2 subcommittees. The
24 subcommittees shall address specific programs and issues, with
25 the leadership committee convening targeted workgroups as
26 needed. The leadership committee may elect to work with an
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1 independent facilitator to solicit and organize feedback,
2 recommendations and meeting participation from a wide variety
3 of community-based stakeholders. If a facilitator is used,
4 they shall be fair and responsive to the needs of all
5 stakeholders involved in the committee.
6 All committee meetings must be accessible, with rotating
7 locations if meetings are held in-person, virtual
8 participation options, and materials and agendas circulated in
9 advance.
10 There shall also be opportunities for direct input by
11 committee members outside of committee meetings, such as via
12 individual meetings, surveys, emails and calls, to ensure
13 robust participation by stakeholders with limited capacity and
14 ability to attend committee meetings. Committee meetings shall
15 emphasize opportunities to bundle and coordinate delivery of
16 low-income energy efficiency with other programs that serve
17 low-income communities, such as the Illinois Solar for All
18 Program and bill payment assistance programs. Meetings shall
19 include educational opportunities for stakeholders to learn
20 more about these additional offerings, and the committee shall
21 assist in figuring out the best methods for coordinated
22 delivery and implementation of offerings when serving
23 low-income communities. The committee shall directly and
24 equitably influence and inform utility low-income and
25 public-housing energy efficiency programs and priorities.
26 Participating utilities shall implement recommendations from
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1 the committee whenever possible.
2 Participating utilities shall track and report how input
3 from the committee has led to new approaches and changes in
4 their energy efficiency portfolios. This reporting shall occur
5 at committee meetings and in quarterly energy efficiency
6 reports to the Stakeholder Advisory Group and Illinois
7 Commerce Commission, and other relevant reporting mechanisms.
8 Participating utilities shall also report on relevant equity
9 data and metrics requested by the committee, such as energy
10 burden data, geographic, racial, and other relevant
11 demographic data on where programs are being delivered and
12 what populations programs are serving.
13 The Illinois Commerce Commission shall oversee and have
14 relevant staff participate in the committee. The committee
15 shall have a budget of 0.25% of each utility's entire
16 efficiency portfolio funding for a given year. The budget
17 shall be overseen by the Commission. The budget shall be used
18 to provide grants for community-based organizations serving on
19 the leadership committee, stipends for community-based
20 organizations participating in the committee, grants for
21 community-based organizations to do energy efficiency outreach
22 and education, and relevant meeting needs as determined by the
23 leadership committee. The education and outreach shall
24 include, but is not limited to, basic energy efficiency
25 education, information about low-income energy efficiency
26 programs, and information on the committee's purpose,
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1 structure, and activities.
2 (d) Notwithstanding any other provision of law to the
3 contrary, a utility providing approved energy efficiency
4 measures and, if applicable, demand-response measures in the
5 State shall be permitted to recover all reasonable and
6 prudently incurred costs of those measures from all retail
7 customers, except as provided in subsection (l) of this
8 Section, as follows, provided that nothing in this subsection
9 (d) permits the double recovery of such costs from customers:
10 (1) The utility may recover its costs through an
11 automatic adjustment clause tariff filed with and approved
12 by the Commission. The tariff shall be established outside
13 the context of a general rate case. Each year the
14 Commission shall initiate a review to reconcile any
15 amounts collected with the actual costs and to determine
16 the required adjustment to the annual tariff factor to
17 match annual expenditures. To enable the financing of the
18 incremental capital expenditures, including regulatory
19 assets, for electric utilities that serve less than
20 3,000,000 retail customers but more than 500,000 retail
21 customers in the State, the utility's actual year-end
22 capital structure that includes a common equity ratio,
23 excluding goodwill, of up to and including 50% of the
24 total capital structure shall be deemed reasonable and
25 used to set rates.
26 (2) A utility may recover its costs through an energy
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1 efficiency formula rate approved by the Commission under a
2 filing under subsections (f) and (g) of this Section,
3 which shall specify the cost components that form the
4 basis of the rate charged to customers with sufficient
5 specificity to operate in a standardized manner and be
6 updated annually with transparent information that
7 reflects the utility's actual costs to be recovered during
8 the applicable rate year, which is the period beginning
9 with the first billing day of January and extending
10 through the last billing day of the following December.
11 The energy efficiency formula rate shall be implemented
12 through a tariff filed with the Commission under
13 subsections (f) and (g) of this Section that is consistent
14 with the provisions of this paragraph (2) and that shall
15 be applicable to all delivery services customers. The
16 Commission shall conduct an investigation of the tariff in
17 a manner consistent with the provisions of this paragraph
18 (2), subsections (f) and (g) of this Section, and the
19 provisions of Article IX of this Act to the extent they do
20 not conflict with this paragraph (2). The energy
21 efficiency formula rate approved by the Commission shall
22 remain in effect at the discretion of the utility and
23 shall do the following:
24 (A) Provide for the recovery of the utility's
25 actual costs incurred under this Section that are
26 prudently incurred and reasonable in amount consistent
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1 with Commission practice and law. The sole fact that a
2 cost differs from that incurred in a prior calendar
3 year or that an investment is different from that made
4 in a prior calendar year shall not imply the
5 imprudence or unreasonableness of that cost or
6 investment.
7 (B) Reflect the utility's actual year-end capital
8 structure for the applicable calendar year, excluding
9 goodwill, subject to a determination of prudence and
10 reasonableness consistent with Commission practice and
11 law. To enable the financing of the incremental
12 capital expenditures, including regulatory assets, for
13 electric utilities that serve less than 3,000,000
14 retail customers but more than 500,000 retail
15 customers in the State, a participating electric
16 utility's actual year-end capital structure that
17 includes a common equity ratio, excluding goodwill, of
18 up to and including 50% of the total capital structure
19 shall be deemed reasonable and used to set rates.
20 (C) Include a cost of equity, which shall be
21 calculated as the sum of the following:
22 (i) the average for the applicable calendar
23 year of the monthly average yields of 30-year U.S.
24 Treasury bonds published by the Board of Governors
25 of the Federal Reserve System in its weekly H.15
26 Statistical Release or successor publication; and
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1 (ii) 580 basis points.
2 At such time as the Board of Governors of the
3 Federal Reserve System ceases to include the monthly
4 average yields of 30-year U.S. Treasury bonds in its
5 weekly H.15 Statistical Release or successor
6 publication, the monthly average yields of the U.S.
7 Treasury bonds then having the longest duration
8 published by the Board of Governors in its weekly H.15
9 Statistical Release or successor publication shall
10 instead be used for purposes of this paragraph (2).
11 (D) Permit and set forth protocols, subject to a
12 determination of prudence and reasonableness
13 consistent with Commission practice and law, for the
14 following:
15 (i) recovery of incentive compensation expense
16 that is based on the achievement of operational
17 metrics, including metrics related to budget
18 controls, outage duration and frequency, safety,
19 customer service, efficiency and productivity, and
20 environmental compliance; however, this protocol
21 shall not apply if such expense related to costs
22 incurred under this Section is recovered under
23 Article IX or Section 16-108.5 of this Act;
24 incentive compensation expense that is based on
25 net income or an affiliate's earnings per share
26 shall not be recoverable under the energy
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1 efficiency formula rate;
2 (ii) recovery of pension and other
3 post-employment benefits expense, provided that
4 such costs are supported by an actuarial study;
5 however, this protocol shall not apply if such
6 expense related to costs incurred under this
7 Section is recovered under Article IX or Section
8 16-108.5 of this Act;
9 (iii) recovery of existing regulatory assets
10 over the periods previously authorized by the
11 Commission;
12 (iv) as described in subsection (e),
13 amortization of costs incurred under this Section;
14 and
15 (v) projected, weather normalized billing
16 determinants for the applicable rate year.
17 (E) Provide for an annual reconciliation, as
18 described in paragraph (3) of this subsection (d),
19 less any deferred taxes related to the reconciliation,
20 with interest at an annual rate of return equal to the
21 utility's weighted average cost of capital, including
22 a revenue conversion factor calculated to recover or
23 refund all additional income taxes that may be payable
24 or receivable as a result of that return, of the energy
25 efficiency revenue requirement reflected in rates for
26 each calendar year, beginning with the calendar year
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1 in which the utility files its energy efficiency
2 formula rate tariff under this paragraph (2), with
3 what the revenue requirement would have been had the
4 actual cost information for the applicable calendar
5 year been available at the filing date.
6 The utility shall file, together with its tariff, the
7 projected costs to be incurred by the utility during the
8 rate year under the utility's multi-year plan approved
9 under subsections (f) and (g) of this Section, including,
10 but not limited to, the projected capital investment costs
11 and projected regulatory asset balances with
12 correspondingly updated depreciation and amortization
13 reserves and expense, that shall populate the energy
14 efficiency formula rate and set the initial rates under
15 the formula.
16 The Commission shall review the proposed tariff in
17 conjunction with its review of a proposed multi-year plan,
18 as specified in paragraph (5) of subsection (g) of this
19 Section. The review shall be based on the same evidentiary
20 standards, including, but not limited to, those concerning
21 the prudence and reasonableness of the costs incurred by
22 the utility, the Commission applies in a hearing to review
23 a filing for a general increase in rates under Article IX
24 of this Act. The initial rates shall take effect beginning
25 with the January monthly billing period following the
26 Commission's approval.
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1 The tariff's rate design and cost allocation across
2 customer classes shall be consistent with the utility's
3 automatic adjustment clause tariff in effect on June 1,
4 2017 (the effective date of Public Act 99-906); however,
5 the Commission may revise the tariff's rate design and
6 cost allocation in subsequent proceedings under paragraph
7 (3) of this subsection (d).
8 If the energy efficiency formula rate is terminated,
9 the then current rates shall remain in effect until such
10 time as the energy efficiency costs are incorporated into
11 new rates that are set under this subsection (d) or
12 Article IX of this Act, subject to retroactive rate
13 adjustment, with interest, to reconcile rates charged with
14 actual costs.
15 (3) The provisions of this paragraph (3) shall only
16 apply to an electric utility that has elected to file an
17 energy efficiency formula rate under paragraph (2) of this
18 subsection (d). Subsequent to the Commission's issuance of
19 an order approving the utility's energy efficiency formula
20 rate structure and protocols, and initial rates under
21 paragraph (2) of this subsection (d), the utility shall
22 file, on or before June 1 of each year, with the Chief
23 Clerk of the Commission its updated cost inputs to the
24 energy efficiency formula rate for the applicable rate
25 year and the corresponding new charges, as well as the
26 information described in paragraph (9) of subsection (g)
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1 of this Section. Each such filing shall conform to the
2 following requirements and include the following
3 information:
4 (A) The inputs to the energy efficiency formula
5 rate for the applicable rate year shall be based on the
6 projected costs to be incurred by the utility during
7 the rate year under the utility's multi-year plan
8 approved under subsections (f) and (g) of this
9 Section, including, but not limited to, projected
10 capital investment costs and projected regulatory
11 asset balances with correspondingly updated
12 depreciation and amortization reserves and expense.
13 The filing shall also include a reconciliation of the
14 energy efficiency revenue requirement that was in
15 effect for the prior rate year (as set by the cost
16 inputs for the prior rate year) with the actual
17 revenue requirement for the prior rate year
18 (determined using a year-end rate base) that uses
19 amounts reflected in the applicable FERC Form 1 that
20 reports the actual costs for the prior rate year. Any
21 over-collection or under-collection indicated by such
22 reconciliation shall be reflected as a credit against,
23 or recovered as an additional charge to, respectively,
24 with interest calculated at a rate equal to the
25 utility's weighted average cost of capital approved by
26 the Commission for the prior rate year, the charges
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1 for the applicable rate year. Such over-collection or
2 under-collection shall be adjusted to remove any
3 deferred taxes related to the reconciliation, for
4 purposes of calculating interest at an annual rate of
5 return equal to the utility's weighted average cost of
6 capital approved by the Commission for the prior rate
7 year, including a revenue conversion factor calculated
8 to recover or refund all additional income taxes that
9 may be payable or receivable as a result of that
10 return. Each reconciliation shall be certified by the
11 participating utility in the same manner that FERC
12 Form 1 is certified. The filing shall also include the
13 charge or credit, if any, resulting from the
14 calculation required by subparagraph (E) of paragraph
15 (2) of this subsection (d).
16 Notwithstanding any other provision of law to the
17 contrary, the intent of the reconciliation is to
18 ultimately reconcile both the revenue requirement
19 reflected in rates for each calendar year, beginning
20 with the calendar year in which the utility files its
21 energy efficiency formula rate tariff under paragraph
22 (2) of this subsection (d), with what the revenue
23 requirement determined using a year-end rate base for
24 the applicable calendar year would have been had the
25 actual cost information for the applicable calendar
26 year been available at the filing date.
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1 For purposes of this Section, "FERC Form 1" means
2 the Annual Report of Major Electric Utilities,
3 Licensees and Others that electric utilities are
4 required to file with the Federal Energy Regulatory
5 Commission under the Federal Power Act, Sections 3,
6 4(a), 304 and 209, modified as necessary to be
7 consistent with 83 Ill. Adm. Code Part 415 as of May 1,
8 2011. Nothing in this Section is intended to allow
9 costs that are not otherwise recoverable to be
10 recoverable by virtue of inclusion in FERC Form 1.
11 (B) The new charges shall take effect beginning on
12 the first billing day of the following January billing
13 period and remain in effect through the last billing
14 day of the next December billing period regardless of
15 whether the Commission enters upon a hearing under
16 this paragraph (3).
17 (C) The filing shall include relevant and
18 necessary data and documentation for the applicable
19 rate year. Normalization adjustments shall not be
20 required.
21 Within 45 days after the utility files its annual
22 update of cost inputs to the energy efficiency formula
23 rate, the Commission shall with reasonable notice,
24 initiate a proceeding concerning whether the projected
25 costs to be incurred by the utility and recovered during
26 the applicable rate year, and that are reflected in the
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1 inputs to the energy efficiency formula rate, are
2 consistent with the utility's approved multi-year plan
3 under subsections (f) and (g) of this Section and whether
4 the costs incurred by the utility during the prior rate
5 year were prudent and reasonable. The Commission shall
6 also have the authority to investigate the information and
7 data described in paragraph (9) of subsection (g) of this
8 Section, including the proposed adjustment to the
9 utility's return on equity component of its weighted
10 average cost of capital. During the course of the
11 proceeding, each objection shall be stated with
12 particularity and evidence provided in support thereof,
13 after which the utility shall have the opportunity to
14 rebut the evidence. Discovery shall be allowed consistent
15 with the Commission's Rules of Practice, which Rules of
16 Practice shall be enforced by the Commission or the
17 assigned administrative law judge. The Commission shall
18 apply the same evidentiary standards, including, but not
19 limited to, those concerning the prudence and
20 reasonableness of the costs incurred by the utility,
21 during the proceeding as it would apply in a proceeding to
22 review a filing for a general increase in rates under
23 Article IX of this Act. The Commission shall not, however,
24 have the authority in a proceeding under this paragraph
25 (3) to consider or order any changes to the structure or
26 protocols of the energy efficiency formula rate approved
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1 under paragraph (2) of this subsection (d). In a
2 proceeding under this paragraph (3), the Commission shall
3 enter its order no later than the earlier of 195 days after
4 the utility's filing of its annual update of cost inputs
5 to the energy efficiency formula rate or December 15. The
6 utility's proposed return on equity calculation, as
7 described in paragraphs (7) through (9) of subsection (g)
8 of this Section, shall be deemed the final, approved
9 calculation on December 15 of the year in which it is filed
10 unless the Commission enters an order on or before
11 December 15, after notice and hearing, that modifies such
12 calculation consistent with this Section. The Commission's
13 determinations of the prudence and reasonableness of the
14 costs incurred, and determination of such return on equity
15 calculation, for the applicable calendar year shall be
16 final upon entry of the Commission's order and shall not
17 be subject to reopening, reexamination, or collateral
18 attack in any other Commission proceeding, case, docket,
19 order, rule, or regulation; however, nothing in this
20 paragraph (3) shall prohibit a party from petitioning the
21 Commission to rehear or appeal to the courts the order
22 under the provisions of this Act.
23 (e) Beginning on June 1, 2017 (the effective date of
24 Public Act 99-906), a utility subject to the requirements of
25 this Section may elect to defer, as a regulatory asset, up to
26 the full amount of its expenditures incurred under this
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1 Section for each annual period, including, but not limited to,
2 any expenditures incurred above the funding level set by
3 subsection (f) of this Section for a given year. The total
4 expenditures deferred as a regulatory asset in a given year
5 shall be amortized and recovered over a period that is equal to
6 the weighted average of the energy efficiency measure lives
7 implemented for that year that are reflected in the regulatory
8 asset. The unamortized balance shall be recognized as of
9 December 31 for a given year. The utility shall also earn a
10 return on the total of the unamortized balances of all of the
11 energy efficiency regulatory assets, less any deferred taxes
12 related to those unamortized balances, at an annual rate equal
13 to the utility's weighted average cost of capital that
14 includes, based on a year-end capital structure, the utility's
15 actual cost of debt for the applicable calendar year and a cost
16 of equity, which shall be calculated as the sum of the (i) the
17 average for the applicable calendar year of the monthly
18 average yields of 30-year U.S. Treasury bonds published by the
19 Board of Governors of the Federal Reserve System in its weekly
20 H.15 Statistical Release or successor publication; and (ii)
21 580 basis points, including a revenue conversion factor
22 calculated to recover or refund all additional income taxes
23 that may be payable or receivable as a result of that return.
24 Capital investment costs shall be depreciated and recovered
25 over their useful lives consistent with generally accepted
26 accounting principles. The weighted average cost of capital
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1 shall be applied to the capital investment cost balance, less
2 any accumulated depreciation and accumulated deferred income
3 taxes, as of December 31 for a given year.
4 When an electric utility creates a regulatory asset under
5 the provisions of this Section, the costs are recovered over a
6 period during which customers also receive a benefit which is
7 in the public interest. Accordingly, it is the intent of the
8 General Assembly that an electric utility that elects to
9 create a regulatory asset under the provisions of this Section
10 shall recover all of the associated costs as set forth in this
11 Section. After the Commission has approved the prudence and
12 reasonableness of the costs that comprise the regulatory
13 asset, the electric utility shall be permitted to recover all
14 such costs, and the value and recoverability through rates of
15 the associated regulatory asset shall not be limited, altered,
16 impaired, or reduced.
17 (f) Beginning in 2017, each electric utility shall file an
18 energy efficiency plan with the Commission to meet the energy
19 efficiency standards for the next applicable multi-year period
20 beginning January 1 of the year following the filing,
21 according to the schedule set forth in paragraphs (1) through
22 (3) of this subsection (f). If a utility does not file such a
23 plan on or before the applicable filing deadline for the plan,
24 it shall face a penalty of $100,000 per day until the plan is
25 filed.
26 (1) No later than 30 days after June 1, 2017 (the
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1 effective date of Public Act 99-906), each electric
2 utility shall file a 4-year energy efficiency plan
3 commencing on January 1, 2018 that is designed to achieve
4 the cumulative persisting annual savings goals specified
5 in paragraphs (1) through (4) of subsection (b-5) of this
6 Section or in paragraphs (1) through (4) of subsection
7 (b-15) of this Section, as applicable, through
8 implementation of energy efficiency measures; however, the
9 goals may be reduced if the utility's expenditures are
10 limited pursuant to subsection (m) of this Section or, for
11 a utility that serves less than 3,000,000 retail
12 customers, if each of the following conditions are met:
13 (A) the plan's analysis and forecasts of the utility's
14 ability to acquire energy savings demonstrate that
15 achievement of such goals is not cost effective; and (B)
16 the amount of energy savings achieved by the utility as
17 determined by the independent evaluator for the most
18 recent year for which savings have been evaluated
19 preceding the plan filing was less than the average annual
20 amount of savings required to achieve the goals for the
21 applicable 4-year plan period. Except as provided in
22 subsection (m) of this Section, annual increases in
23 cumulative persisting annual savings goals during the
24 applicable 4-year plan period shall not be reduced to
25 amounts that are less than the maximum amount of
26 cumulative persisting annual savings that is forecast to
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1 be cost-effectively achievable during the 4-year plan
2 period. The Commission shall review any proposed goal
3 reduction as part of its review and approval of the
4 utility's proposed plan.
5 (2) No later than March 1, 2021, each electric utility
6 shall file a 4-year energy efficiency plan commencing on
7 January 1, 2022 that is designed to achieve the cumulative
8 persisting annual savings goals specified in paragraphs
9 (5) through (8) of subsection (b-5) of this Section or in
10 paragraphs (5) through (8) of subsection (b-15) of this
11 Section, as applicable, through implementation of energy
12 efficiency measures; however, the goals may be reduced if
13 either (1) clear and convincing evidence demonstrates,
14 through independent analysis, that the expenditure limits
15 in subsection (m) of this Section preclude full
16 achievement of the goals or (2) each of the following
17 conditions are met: (A) the plan's analysis and forecasts
18 of the utility's ability to acquire energy savings
19 demonstrate by clear and convincing evidence and through
20 independent analysis that achievement of such goals is not
21 cost effective; and (B) the amount of energy savings
22 achieved by the utility as determined by the independent
23 evaluator for the most recent year for which savings have
24 been evaluated preceding the plan filing was less than the
25 average annual amount of savings required to achieve the
26 goals for the applicable 4-year plan period. If there is
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1 not clear and convincing evidence that achieving the
2 savings goals specified in paragraph (b-5) or (b-15) of
3 this Section is possible both cost-effectively and within
4 the expenditure limits in subsection (m), such savings
5 goals shall not be reduced. Except as provided in
6 subsection (m) of this Section, annual increases in
7 cumulative persisting annual savings goals during the
8 applicable 4-year plan period shall not be reduced to
9 amounts that are less than the maximum amount of
10 cumulative persisting annual savings that is forecast to
11 be cost-effectively achievable during the 4-year plan
12 period. The Commission shall review any proposed goal
13 reduction as part of its review and approval of the
14 utility's proposed plan.
15 (3) No later than March 1, 2025, each electric utility
16 shall file a 4-year energy efficiency plan commencing on
17 January 1, 2026 that is designed to achieve the
18 incremental annual savings as defined by subsection (b-16)
19 the cumulative persisting annual savings goals specified
20 in paragraphs (9) through (12) of subsection (b-5) of this
21 Section or in paragraphs (9) through (12) of subsection
22 (b-15) of this Section, as applicable, through
23 implementation of energy efficiency measures; however, the
24 goals may be reduced if either (1) clear and convincing
25 evidence demonstrates, through independent analysis, that
26 the expenditure limits in subsection (m) of this Section
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1 preclude full achievement of the goals or (2) each of the
2 following conditions are met: (A) the plan's analysis and
3 forecasts of the utility's ability to acquire energy
4 savings demonstrate by clear and convincing evidence and
5 through independent analysis that achievement of such
6 goals is not cost effective; and (B) the amount of energy
7 savings achieved by the utility as determined by the
8 independent evaluator for the most recent year for which
9 savings have been evaluated preceding the plan filing was
10 less than the average annual amount of savings required to
11 achieve the goals for the applicable 4-year plan period.
12 If there is not clear and convincing evidence that
13 achieving the savings goals specified in subsection (b-16)
14 paragraphs (b-5) or (b-15) of this Section is possible
15 both cost-effectively and within the expenditure limits in
16 subsection (m), such savings goals shall not be reduced.
17 Except as provided in subsection (m) of this Section,
18 annual increases in cumulative persisting annual savings
19 goals during the applicable 4-year plan period shall not
20 be reduced to amounts that are less than the maximum
21 amount of cumulative persisting annual savings that is
22 forecast to be cost-effectively achievable during the
23 4-year plan period. The Commission shall review any
24 proposed goal reduction as part of its review and approval
25 of the utility's proposed plan.
26 (4) No later than March 1, 2029, and every 4 years
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1 thereafter, each electric utility shall file a 4-year
2 energy efficiency plan commencing on January 1, 2030, and
3 every 4 years thereafter, respectively, that is designed
4 to achieve the incremental annual savings as defined by
5 subsection (b-16) cumulative persisting annual savings
6 goals established by the Illinois Commerce Commission
7 pursuant to direction of subsections (b-5) and (b-15) of
8 this Section, as applicable, through implementation of
9 energy efficiency measures; however, the goals may be
10 reduced if either (1) clear and convincing evidence and
11 independent analysis demonstrates that the expenditure
12 limits in subsection (m) of this Section preclude full
13 achievement of the goals or (2) each of the following
14 conditions are met: (A) the plan's analysis and forecasts
15 of the utility's ability to acquire energy savings
16 demonstrate by clear and convincing evidence and through
17 independent analysis that achievement of such goals is not
18 cost-effective; and (B) the amount of energy savings
19 achieved by the utility as determined by the independent
20 evaluator for the most recent year for which savings have
21 been evaluated preceding the plan filing was less than the
22 average annual amount of savings required to achieve the
23 goals for the applicable 4-year plan period. If there is
24 not clear and convincing evidence that achieving the
25 savings goals specified in paragraphs (b-5) or (b-15) of
26 this Section is possible both cost-effectively and within
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1 the expenditure limits in subsection (m), such savings
2 goals shall not be reduced. Except as provided in
3 subsection (m) of this Section, annual increases in
4 cumulative persisting annual savings goals during the
5 applicable 4-year plan period shall not be reduced to
6 amounts that are less than the maximum amount of
7 cumulative persisting annual savings that is forecast to
8 be cost-effectively achievable during the 4-year plan
9 period. The Commission shall review any proposed goal
10 reduction as part of its review and approval of the
11 utility's proposed plan.
12 Each utility's plan shall set forth the utility's
13 proposals to meet the energy efficiency standards identified
14 in subsection (b-5), or (b-15), or (b-16) as applicable and as
15 such standards may have been modified under this subsection
16 (f), taking into account the unique circumstances of the
17 utility's service territory. For those plans commencing on
18 January 1, 2018, the Commission shall seek public comment on
19 the utility's plan and shall issue an order approving or
20 disapproving each plan no later than 105 days after June 1,
21 2017 (the effective date of Public Act 99-906). For those
22 plans commencing after December 31, 2021, the Commission shall
23 seek public comment on the utility's plan and shall issue an
24 order approving or disapproving each plan within 6 months
25 after its submission. If the Commission disapproves a plan,
26 the Commission shall, within 30 days, describe in detail the
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1 reasons for the disapproval and describe a path by which the
2 utility may file a revised draft of the plan to address the
3 Commission's concerns satisfactorily. If the utility does not
4 refile with the Commission within 60 days, the utility shall
5 be subject to penalties at a rate of $100,000 per day until the
6 plan is filed. This process shall continue, and penalties
7 shall accrue, until the utility has successfully filed a
8 portfolio of energy efficiency and demand-response measures.
9 Penalties shall be deposited into the Energy Efficiency Trust
10 Fund.
11 (g) In submitting proposed plans and funding levels under
12 subsection (f) of this Section to meet the savings goals
13 identified in subsection (b-5), or (b-15), or (b-16) of this
14 Section, as applicable, the utility shall:
15 (1) Demonstrate that its proposed energy efficiency
16 measures will achieve the applicable requirements that are
17 identified in subsection (b-5), or (b-15), or (b-16) of
18 this Section, as modified by subsection (f) of this
19 Section.
20 (2) (Blank).
21 (2.5) Demonstrate consideration of program options for
22 (A) advancing new building codes, appliance standards, and
23 municipal regulations governing existing and new building
24 efficiency improvements and (B) supporting efforts to
25 improve compliance with new building codes, appliance
26 standards and municipal regulations, as potentially
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1 cost-effective means of acquiring energy savings to count
2 toward savings goals.
3 (3) Demonstrate that its overall portfolio of
4 measures, not including low-income programs described in
5 subsection (c) of this Section, is cost-effective using
6 the total resource cost test or complies with paragraphs
7 (1) through (3) of subsection (f) of this Section and
8 represents a diverse cross-section of opportunities for
9 customers of all rate classes, other than those customers
10 described in subsection (l) of this Section, to
11 participate in the programs. Individual measures need not
12 be cost effective.
13 (3.5) Demonstrate that the utility's plan integrates
14 the delivery of energy efficiency programs with natural
15 gas efficiency programs, programs promoting distributed
16 solar, programs promoting demand response and other
17 efforts to address bill payment issues, including, but not
18 limited to, LIHEAP and the Percentage of Income Payment
19 Plan, to the extent such integration is practical and has
20 the potential to enhance customer engagement, minimize
21 market confusion, or reduce administrative costs.
22 (4) Present a third-party energy efficiency
23 implementation program subject to the following
24 requirements:
25 (A) beginning with the year commencing January 1,
26 2019, electric utilities that serve more than
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1 3,000,000 retail customers in the State shall fund
2 third-party energy efficiency programs in an amount
3 that is no less than $25,000,000 per year, and
4 electric utilities that serve less than 3,000,000
5 retail customers but more than 500,000 retail
6 customers in the State shall fund third-party energy
7 efficiency programs in an amount that is no less than
8 $8,350,000 per year;
9 (B) during 2018, the utility shall conduct a
10 solicitation process for purposes of requesting
11 proposals from third-party vendors for those
12 third-party energy efficiency programs to be offered
13 during one or more of the years commencing January 1,
14 2019, January 1, 2020, and January 1, 2021; for those
15 multi-year plans commencing on January 1, 2022 and
16 January 1, 2026, the utility shall conduct a
17 solicitation process during 2021 and 2025,
18 respectively, for purposes of requesting proposals
19 from third-party vendors for those third-party energy
20 efficiency programs to be offered during one or more
21 years of the respective multi-year plan period; for
22 each solicitation process, the utility shall identify
23 the sector, technology, or geographical area for which
24 it is seeking requests for proposals; the solicitation
25 process must be either for programs that fill gaps in
26 the utility's program portfolio and for programs that
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1 target low-income customers, business sectors,
2 building types, geographies, or other specific parts
3 of its customer base with initiatives that would be
4 more effective at reaching these customer segments
5 than the utilities' programs filed in its energy
6 efficiency plans;
7 (C) the utility shall propose the bidder
8 qualifications, performance measurement process, and
9 contract structure, which must include a performance
10 payment mechanism and general terms and conditions;
11 the proposed qualifications, process, and structure
12 shall be subject to Commission approval; and
13 (D) the utility shall retain an independent third
14 party to score the proposals received through the
15 solicitation process described in this paragraph (4),
16 rank them according to their cost per lifetime
17 kilowatt-hours saved, and assemble the portfolio of
18 third-party programs.
19 The electric utility shall recover all costs
20 associated with Commission-approved, third-party
21 administered programs regardless of the success of those
22 programs.
23 (4.5) Implement cost-effective demand-response
24 measures to reduce peak demand by 0.1% over the prior year
25 for eligible retail customers, as defined in Section
26 16-111.5 of this Act, and for customers that elect hourly
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1 service from the utility pursuant to Section 16-107 of
2 this Act, provided those customers have not been declared
3 competitive. This requirement continues until December 31,
4 2026.
5 (5) Include a proposed or revised cost-recovery tariff
6 mechanism, as provided for under subsection (d) of this
7 Section, to fund the proposed energy efficiency and
8 demand-response measures and to ensure the recovery of the
9 prudently and reasonably incurred costs of
10 Commission-approved programs.
11 (6) Provide for an annual independent evaluation of
12 the performance of the cost-effectiveness of the utility's
13 portfolio of measures, as well as a full review of the
14 multi-year plan results of the broader net program impacts
15 and, to the extent practical, for adjustment of the
16 measures on a going-forward basis as a result of the
17 evaluations. The resources dedicated to evaluation shall
18 not exceed 3% of portfolio resources in any given year.
19 (7) For electric utilities that serve more than
20 500,000 3,000,000 retail customers in the State:
21 (A) Through December 31, 2025, provide for an
22 adjustment to the return on equity component of the
23 utility's weighted average cost of capital calculated
24 under subsection (d) of this Section:
25 (i) If the independent evaluator determines
26 that the utility achieved a cumulative persisting
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1 annual savings that is less than the applicable
2 annual incremental goal, then the return on equity
3 component shall be reduced by a maximum of 200
4 basis points in the event that the utility
5 achieved no more than 75% of such goal. If the
6 utility achieved more than 75% of the applicable
7 annual incremental goal but less than 100% of such
8 goal, then the return on equity component shall be
9 reduced by 8 basis points for each percent by
10 which the utility failed to achieve the goal.
11 (ii) If the independent evaluator determines
12 that the utility achieved a cumulative persisting
13 annual savings that is more than the applicable
14 annual incremental goal, then the return on equity
15 component shall be increased by a maximum of 200
16 basis points in the event that the utility
17 achieved at least 125% of such goal. If the
18 utility achieved more than 100% of the applicable
19 annual incremental goal but less than 125% of such
20 goal, then the return on equity component shall be
21 increased by 8 basis points for each percent by
22 which the utility achieved above the goal. If the
23 applicable annual incremental goal was reduced
24 under paragraph (1) or (2) of subsection (f) of
25 this Section, then the following adjustments shall
26 be made to the calculations described in this item
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1 (ii):
2 (aa) the calculation for determining
3 achievement that is at least 125% of the
4 applicable annual incremental goal shall use
5 the unreduced applicable annual incremental
6 goal to set the value; and
7 (bb) the calculation for determining
8 achievement that is less than 125% but more
9 than 100% of the applicable annual incremental
10 goal shall use the reduced applicable annual
11 incremental goal to set the value for 100%
12 achievement of the goal and shall use the
13 unreduced goal to set the value for 125%
14 achievement. The 8 basis point value shall
15 also be modified, as necessary, so that the
16 200 basis points are evenly apportioned among
17 each percentage point value between 100% and
18 125% achievement.
19 (B) For the period January 1, 2026 through
20 December 31, 2029 and in all subsequent 4-year
21 periods, provide for an adjustment to the return on
22 equity component of the utility's weighted average
23 cost of capital calculated under subsection (d) of
24 this Section:
25 (i) If the incremental annual savings goal
26 specified in subsection (b-16) of this Section is
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1 unmodified, and if the independent evaluator
2 determines that the utility achieved lifetime
3 energy savings that is less than the product of
4 the incremental annual savings goal and minimum
5 average savings life specified in subsection
6 (b-16) of this Section, then the return on equity
7 component shall be reduced by a maximum of 200
8 basis points if the utility achieved no more than
9 66% of such lifetime savings goal. If the utility
10 achieved more than 66% but less than 100% of such
11 goal, then the return on equity component shall be
12 reduced by 6 basis points for each percent by
13 which the utility failed to achieve the goal If
14 the independent evaluator determines that the
15 utility achieved a cumulative persisting annual
16 savings that is less than the applicable annual
17 incremental goal, then the return on equity
18 component shall be reduced by a maximum of 200
19 basis points in the event that the utility
20 achieved no more than 66% of such goal. If the
21 utility achieved more than 66% of the applicable
22 annual incremental goal but less than 100% of such
23 goal, then the return on equity component shall be
24 reduced by 6 basis points for each percent by
25 which the utility failed to achieve the goal.
26 (ii) If the incremental annual savings goal
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1 specified in subsection(b-16) of this Section is
2 unmodified, and if the independent evaluator
3 determines that the utility achieved lifetime
4 energy savings that is more than the product of
5 the incremental annual savings goal and minimum
6 average savings life specified in subsection
7 (b-16) of this Section, then the return on equity
8 component shall be increased by a maximum of 200
9 basis points if the utility achieved at least 134%
10 of such lifetime savings goal. If the utility
11 achieved more than 100% but less than 134% of such
12 goal, then the return on equity component shall be
13 increased by 6 basis points for each percent by
14 which the utility achieved above the goal. If the
15 independent evaluator determines that the utility
16 achieved a cumulative persisting annual savings
17 that is more than the applicable annual
18 incremental goal, then the return on equity
19 component shall be increased by a maximum of 200
20 basis points in the event that the utility
21 achieved at least 134% of such goal. If the
22 utility achieved more than 100% of the applicable
23 annual incremental goal but less than 134% of such
24 goal, then the return on equity component shall be
25 increased by 6 basis points for each percent by
26 which the utility achieved above the goal. If the
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1 applicable annual incremental goal was reduced
2 under paragraph (3) of subsection (f) of this
3 Section, then the following adjustments shall be
4 made to the calculations described in this item
5 (ii):
6 (iii) If the incremental annual savings goal
7 specified in subsection (b-16) of this Section is
8 reduced pursuant to paragraphs (3) or (4) of
9 subsection (f), then the return on equity shall be
10 reduced by 10 basis points for every percent by
11 which the utility fails to achieved the modified
12 goal, up to a maximum of a 200 basis point
13 reduction. (aa) the calculation for determining
14 achievement that is at least 134% of the
15 applicable annual incremental goal shall use the
16 unreduced applicable annual incremental goal to
17 set the value; and
18 (iv) If the incremental annual savings goal
19 specified in subsection (b-16) of this Section is
20 reduced pursuant to paragraphs (3) or (4) of
21 subsection (f), the return on equity component
22 shall be increased by a maximum of 200 basis
23 points if the utility achieved at least 134% of
24 the unmodified lifetime savings goal. If the
25 utility achieved more than 100% of the modified
26 goal but less than 134% of the unmodified goal,
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1 then the return on equity component shall be
2 linearly interpolated between 0 increase for just
3 meeting 100% of the modified goal and a 200 basis
4 point increase for achieving 134% of the
5 unmodified goal (bb) the calculation for
6 determining achievement that is less than 134% but
7 more than 100% of the applicable annual
8 incremental goal shall use the reduced applicable
9 annual incremental goal to set the value for 100%
10 achievement of the goal and shall use the
11 unreduced goal to set the value for 134%
12 achievement. The 6 basis point value shall also be
13 modified, as necessary, so that the 200 basis
14 points are evenly apportioned among each
15 percentage point value between 100% and 134%
16 achievement.
17 (C) Notwithstanding the provisions of
18 subparagraphs (A) and (B) of this paragraph (7), if
19 the applicable annual incremental goal for an electric
20 utility is ever less than 0.6% of deemed average
21 weather normalized sales of electric power and energy
22 during calendar years 2014, 2015, and 2016, an
23 adjustment to the return on equity component of the
24 utility's weighted average cost of capital calculated
25 under subsection (d) of this Section shall be made as
26 follows:
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1 (i) If the independent evaluator determines
2 that the utility achieved a cumulative persisting
3 annual savings that is less than would have been
4 achieved had the applicable annual incremental
5 goal been achieved, then the return on equity
6 component shall be reduced by a maximum of 200
7 basis points if the utility achieved no more than
8 75% of its applicable annual total savings
9 requirement as defined in paragraph (7.5) of this
10 subsection. If the utility achieved more than 75%
11 of the applicable annual total savings requirement
12 but less than 100% of such goal, then the return on
13 equity component shall be reduced by 8 basis
14 points for each percent by which the utility
15 failed to achieve the goal.
16 (ii) If the independent evaluator determines
17 that the utility achieved a cumulative persisting
18 annual savings that is more than would have been
19 achieved had the applicable annual incremental
20 goal been achieved, then the return on equity
21 component shall be increased by a maximum of 200
22 basis points if the utility achieved at least 125%
23 of its applicable annual total savings
24 requirement. If the utility achieved more than
25 100% of the applicable annual total savings
26 requirement but less than 125% of such goal, then
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1 the return on equity component shall be increased
2 by 8 basis points for each percent by which the
3 utility achieved above the applicable annual total
4 savings requirement. If the applicable annual
5 incremental goal was reduced under paragraph (1)
6 or (2) of subsection (f) of this Section, then the
7 following adjustments shall be made to the
8 calculations described in this item (ii):
9 (aa) the calculation for determining
10 achievement that is at least 125% of the
11 applicable annual total savings requirement
12 shall use the unreduced applicable annual
13 incremental goal to set the value; and
14 (bb) the calculation for determining
15 achievement that is less than 125% but more
16 than 100% of the applicable annual total
17 savings requirement shall use the reduced
18 applicable annual incremental goal to set the
19 value for 100% achievement of the goal and
20 shall use the unreduced goal to set the value
21 for 125% achievement. The 8 basis point value
22 shall also be modified, as necessary, so that
23 the 200 basis points are evenly apportioned
24 among each percentage point value between 100%
25 and 125% achievement.
26 (7.5) For purposes of this Section, the term
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1 "applicable annual incremental goal" means the difference
2 between the cumulative persisting annual savings goal for
3 the calendar year that is the subject of the independent
4 evaluator's determination and the cumulative persisting
5 annual savings goal for the immediately preceding calendar
6 year, as such goals are defined in subsections (b-5) and
7 (b-15) of this Section and as these goals may have been
8 modified as provided for under subsection (b-20) and
9 paragraphs (1) and (2) through (3) of subsection (f) of
10 this Section. Under subsections (b), (b-5), (b-10), and
11 (b-15) of this Section, a utility must first replace
12 energy savings from measures that have expired before any
13 progress towards achievement of its applicable annual
14 incremental goal may be counted. Savings may expire
15 because measures installed in previous years have reached
16 the end of their lives, because measures installed in
17 previous years are producing lower savings in the current
18 year than in the previous year, or for other reasons
19 identified by independent evaluators. Notwithstanding
20 anything else set forth in this Section, the difference
21 between the actual annual incremental savings achieved in
22 any given year, including the replacement of energy
23 savings that have expired, and the applicable annual
24 incremental goal shall not affect adjustments to the
25 return on equity for subsequent calendar years under this
26 subsection (g).
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1 In this Section, "applicable annual total savings
2 requirement" means the total amount of new annual savings
3 that the utility must achieve in any given year to achieve
4 the applicable annual incremental goal. This is equal to
5 the applicable annual incremental goal plus the total new
6 annual savings that are required to replace savings that
7 expired in or at the end of the previous year.
8 (8) (Blank). For electric utilities that serve less
9 than 3,000,000 retail customers but more than 500,000
10 retail customers in the State:
11 (A) Through December 31, 2025, the applicable
12 annual incremental goal shall be compared to the
13 annual incremental savings as determined by the
14 independent evaluator.
15 (i) The return on equity component shall be
16 reduced by 8 basis points for each percent by
17 which the utility did not achieve 84.4% of the
18 applicable annual incremental goal.
19 (ii) The return on equity component shall be
20 increased by 8 basis points for each percent by
21 which the utility exceeded 100% of the applicable
22 annual incremental goal.
23 (iii) The return on equity component shall not
24 be increased or decreased if the annual
25 incremental savings as determined by the
26 independent evaluator is greater than 84.4% of the
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1 applicable annual incremental goal and less than
2 100% of the applicable annual incremental goal.
3 (iv) The return on equity component shall not
4 be increased or decreased by an amount greater
5 than 200 basis points pursuant to this
6 subparagraph (A).
7 (B) For the period of January 1, 2026 through
8 December 31, 2029 and in all subsequent 4-year
9 periods, the applicable annual incremental goal shall
10 be compared to the annual incremental savings as
11 determined by the independent evaluator.
12 (i) The return on equity component shall be
13 reduced by 6 basis points for each percent by
14 which the utility did not achieve 100% of the
15 applicable annual incremental goal.
16 (ii) The return on equity component shall be
17 increased by 6 basis points for each percent by
18 which the utility exceeded 100% of the applicable
19 annual incremental goal.
20 (iii) The return on equity component shall not
21 be increased or decreased by an amount greater
22 than 200 basis points pursuant to this
23 subparagraph (B).
24 (C) Notwithstanding provisions in subparagraphs
25 (A) and (B) of paragraph (7) of this subsection, if the
26 applicable annual incremental goal for an electric
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1 utility is ever less than 0.6% of deemed average
2 weather normalized sales of electric power and energy
3 during calendar years 2014, 2015 and 2016, an
4 adjustment to the return on equity component of the
5 utility's weighted average cost of capital calculated
6 under subsection (d) of this Section shall be made as
7 follows:
8 (i) The return on equity component shall be
9 reduced by 8 basis points for each percent by
10 which the utility did not achieve 100% of the
11 applicable annual total savings requirement.
12 (ii) The return on equity component shall be
13 increased by 8 basis points for each percent by
14 which the utility exceeded 100% of the applicable
15 annual total savings requirement.
16 (iii) The return on equity component shall not
17 be increased or decreased by an amount greater
18 than 200 basis points pursuant to this
19 subparagraph (C).
20 (D) If the applicable annual incremental goal was
21 reduced under paragraph (1), (2), (3), or (4) of
22 subsection (f) of this Section, then the following
23 adjustments shall be made to the calculations
24 described in subparagraphs (A), (B), and (C) of this
25 paragraph (8):
26 (i) The calculation for determining
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1 achievement that is at least 125% or 134%, as
2 applicable, of the applicable annual incremental
3 goal or the applicable annual total savings
4 requirement, as applicable, shall use the
5 unreduced applicable annual incremental goal to
6 set the value.
7 (ii) For the period through December 31, 2025,
8 the calculation for determining achievement that
9 is less than 125% but more than 100% of the
10 applicable annual incremental goal or the
11 applicable annual total savings requirement, as
12 applicable, shall use the reduced applicable
13 annual incremental goal to set the value for 100%
14 achievement of the goal and shall use the
15 unreduced goal to set the value for 125%
16 achievement. The 8 basis point value shall also be
17 modified, as necessary, so that the 200 basis
18 points are evenly apportioned among each
19 percentage point value between 100% and 125%
20 achievement.
21 (iii) For the period of January 1, 2026
22 through December 31, 2029 and all subsequent
23 4-year periods, the calculation for determining
24 achievement that is less than 125% or 134%, as
25 applicable, but more than 100% of the applicable
26 annual incremental goal or the applicable annual
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1 total savings requirement, as applicable, shall
2 use the reduced applicable annual incremental goal
3 to set the value for 100% achievement of the goal
4 and shall use the unreduced goal to set the value
5 for 125% achievement. The 6 basis-point value or 8
6 basis-point value, as applicable, shall also be
7 modified, as necessary, so that the 200 basis
8 points are evenly apportioned among each
9 percentage point value between 100% and 125% or
10 between 100% and 134% achievement, as applicable.
11 (9) The utility shall submit the energy savings data
12 to the independent evaluator no later than 30 days after
13 the close of the plan year. The independent evaluator
14 shall determine the cumulative persisting annual savings
15 for a given plan year, as well as an estimate of job
16 impacts and other macroeconomic impacts of the efficiency
17 programs for that year, no later than 120 days after the
18 close of the plan year. The utility shall submit an
19 informational filing to the Commission no later than 160
20 days after the close of the plan year that attaches the
21 independent evaluator's final report identifying the
22 cumulative persisting annual savings for the year and
23 calculates, under paragraph (7) or (8) of this subsection
24 (g), as applicable, any resulting change to the utility's
25 return on equity component of the weighted average cost of
26 capital applicable to the next plan year beginning with
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1 the January monthly billing period and extending through
2 the December monthly billing period. However, if the
3 utility recovers the costs incurred under this Section
4 under paragraphs (2) and (3) of subsection (d) of this
5 Section, then the utility shall not be required to submit
6 such informational filing, and shall instead submit the
7 information that would otherwise be included in the
8 informational filing as part of its filing under paragraph
9 (3) of such subsection (d) that is due on or before June 1
10 of each year.
11 For those utilities that must submit the informational
12 filing, the Commission may, on its own motion or by
13 petition, initiate an investigation of such filing,
14 provided, however, that the utility's proposed return on
15 equity calculation shall be deemed the final, approved
16 calculation on December 15 of the year in which it is filed
17 unless the Commission enters an order on or before
18 December 15, after notice and hearing, that modifies such
19 calculation consistent with this Section.
20 The adjustments to the return on equity component
21 described in paragraph paragraphs (7) and (8) of this
22 subsection (g) shall be applied as described in such
23 paragraphs through a separate tariff mechanism, which
24 shall be filed by the utility under subsections (f) and
25 (g) of this Section.
26 (9.5) The utility must demonstrate how it will ensure
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1 that program implementation contractors and energy
2 efficiency installation vendors will promote workforce
3 equity and quality jobs.
4 (9.6) Utilities shall collect data necessary to ensure
5 compliance with paragraph (9.5) no less than quarterly and
6 shall communicate progress toward compliance with
7 paragraph (9.5) to program implementation contractors and
8 energy efficiency installation vendors no less than
9 quarterly. Utilities shall work with relevant vendors,
10 providing education, training, and other resources needed
11 to ensure compliance and, where necessary, adjusting or
12 terminating work with vendors that cannot assist with
13 compliance.
14 (10) Utilities required to implement efficiency
15 programs under subsections (b-5), and (b-10), and (b-16)
16 shall report annually to the Illinois Commerce Commission
17 and the General Assembly on how hiring, contracting, job
18 training, and other practices related to its energy
19 efficiency programs enhance the diversity of vendors
20 working on such programs. These reports must include data
21 on vendor and employee diversity, including data on the
22 implementation of paragraphs (9.5) and (9.6). If the
23 utility is not meeting the requirements of paragraphs
24 (9.5) and (9.6), the utility shall submit a plan to adjust
25 their activities so that they meet the requirements of
26 paragraphs (9.5) and (9.6) within the following year.
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1 (h) No more than 4% of energy efficiency and
2 demand-response program revenue may be allocated for research,
3 development, or pilot deployment of new equipment or measures.
4 Electric utilities shall work with interested stakeholders to
5 formulate a plan for how these funds should be spent,
6 incorporate statewide approaches for these allocations, and
7 file a 4-year plan that demonstrates that collaboration. If a
8 utility files a request for modified annual energy savings
9 goals with the Commission, then a utility shall forgo spending
10 portfolio dollars on research and development proposals.
11 (i) When practicable, electric utilities shall incorporate
12 advanced metering infrastructure data into the planning,
13 implementation, and evaluation of energy efficiency measures
14 and programs, subject to the data privacy and confidentiality
15 protections of applicable law.
16 (j) The independent evaluator shall follow the guidelines
17 and use the savings set forth in Commission-approved energy
18 efficiency policy manuals and technical reference manuals, as
19 each may be updated from time to time. Until such time as
20 measure life values for energy efficiency measures implemented
21 for low-income households under subsection (c) of this Section
22 are incorporated into such Commission-approved manuals, the
23 low-income measures shall have the same measure life values
24 that are established for same measures implemented in
25 households that are not low-income households.
26 (k) Notwithstanding any provision of law to the contrary,
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1 an electric utility subject to the requirements of this
2 Section may file a tariff cancelling an automatic adjustment
3 clause tariff in effect under this Section or Section 8-103,
4 which shall take effect no later than one business day after
5 the date such tariff is filed. Thereafter, the utility shall
6 be authorized to defer and recover its expenditures incurred
7 under this Section through a new tariff authorized under
8 subsection (d) of this Section or in the utility's next rate
9 case under Article IX or Section 16-108.5 of this Act, with
10 interest at an annual rate equal to the utility's weighted
11 average cost of capital as approved by the Commission in such
12 case. If the utility elects to file a new tariff under
13 subsection (d) of this Section, the utility may file the
14 tariff within 10 days after June 1, 2017 (the effective date of
15 Public Act 99-906), and the cost inputs to such tariff shall be
16 based on the projected costs to be incurred by the utility
17 during the calendar year in which the new tariff is filed and
18 that were not recovered under the tariff that was cancelled as
19 provided for in this subsection. Such costs shall include
20 those incurred or to be incurred by the utility under its
21 multi-year plan approved under subsections (f) and (g) of this
22 Section, including, but not limited to, projected capital
23 investment costs and projected regulatory asset balances with
24 correspondingly updated depreciation and amortization reserves
25 and expense. The Commission shall, after notice and hearing,
26 approve, or approve with modification, such tariff and cost
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1 inputs no later than 75 days after the utility filed the
2 tariff, provided that such approval, or approval with
3 modification, shall be consistent with the provisions of this
4 Section to the extent they do not conflict with this
5 subsection (k). The tariff approved by the Commission shall
6 take effect no later than 5 days after the Commission enters
7 its order approving the tariff.
8 No later than 60 days after the effective date of the
9 tariff cancelling the utility's automatic adjustment clause
10 tariff, the utility shall file a reconciliation that
11 reconciles the moneys collected under its automatic adjustment
12 clause tariff with the costs incurred during the period
13 beginning June 1, 2016 and ending on the date that the electric
14 utility's automatic adjustment clause tariff was cancelled. In
15 the event the reconciliation reflects an under-collection, the
16 utility shall recover the costs as specified in this
17 subsection (k). If the reconciliation reflects an
18 over-collection, the utility shall apply the amount of such
19 over-collection as a one-time credit to retail customers'
20 bills.
21 (l) (Blank). For the calendar years covered by a
22 multi-year plan commencing after December 31, 2017,
23 subsections (a) through (j) of this Section do not apply to
24 eligible large private energy customers that have chosen to
25 opt out of multi-year plans consistent with this subsection
26 (1).
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1 (1) For purposes of this subsection (l), "eligible
2 large private energy customer" means any retail customers,
3 except for federal, State, municipal, and other public
4 customers, of an electric utility that serves more than
5 3,000,000 retail customers, except for federal, State,
6 municipal and other public customers, in the State and
7 whose total highest 30 minute demand was more than 10,000
8 kilowatts, or any retail customers of an electric utility
9 that serves less than 3,000,000 retail customers but more
10 than 500,000 retail customers in the State and whose total
11 highest 15 minute demand was more than 10,000 kilowatts.
12 For purposes of this subsection (l), "retail customer" has
13 the meaning set forth in Section 16-102 of this Act.
14 However, for a business entity with multiple sites located
15 in the State, where at least one of those sites qualifies
16 as an eligible large private energy customer, then any of
17 that business entity's sites, properly identified on a
18 form for notice, shall be considered eligible large
19 private energy customers for the purposes of this
20 subsection (l). A determination of whether this subsection
21 is applicable to a customer shall be made for each
22 multi-year plan beginning after December 31, 2017. The
23 criteria for determining whether this subsection (l) is
24 applicable to a retail customer shall be based on the 12
25 consecutive billing periods prior to the start of the
26 first year of each such multi-year plan.
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1 (2) Within 45 days after September 15, 2021 (the
2 effective date of Public Act 102-662), the Commission
3 shall prescribe the form for notice required for opting
4 out of energy efficiency programs. The notice must be
5 submitted to the retail electric utility 12 months before
6 the next energy efficiency planning cycle. However, within
7 120 days after the Commission's initial issuance of the
8 form for notice, eligible large private energy customers
9 may submit a form for notice to an electric utility. The
10 form for notice for opting out of energy efficiency
11 programs shall include all of the following:
12 (A) a statement indicating that the customer has
13 elected to opt out;
14 (B) the account numbers for the customer accounts
15 to which the opt out shall apply;
16 (C) the mailing address associated with the
17 customer accounts identified under subparagraph (B);
18 (D) an American Society of Heating, Refrigerating,
19 and Air-Conditioning Engineers (ASHRAE) level 2 or
20 higher audit report conducted by an independent
21 third-party expert identifying cost-effective energy
22 efficiency project opportunities that could be
23 invested in over the next 10 years. A retail customer
24 with specialized processes may utilize a self-audit
25 process in lieu of the ASHRAE audit;
26 (E) a description of the customer's plans to
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1 reallocate the funds toward internal energy efficiency
2 efforts identified in the subparagraph (D) report,
3 including, but not limited to: (i) strategic energy
4 management or other programs, including descriptions
5 of targeted buildings, equipment and operations; (ii)
6 eligible energy efficiency measures; and (iii)
7 expected energy savings, itemized by technology. If
8 the subparagraph (D) audit report identifies that the
9 customer currently utilizes the best available energy
10 efficient technology, equipment, programs, and
11 operations, the customer may provide a statement that
12 more efficient technology, equipment, programs, and
13 operations are not reasonably available as a means of
14 satisfying this subparagraph (E); and
15 (F) the effective date of the opt out, which will
16 be the next January 1 following notice of the opt out.
17 (3) Upon receipt of a properly and timely noticed
18 request for opt out submitted by an eligible large private
19 energy customer, the retail electric utility shall grant
20 the request, file the request with the Commission and,
21 beginning January 1 of the following year, the opted out
22 customer shall no longer be assessed the costs of the plan
23 and shall be prohibited from participating in that 4-year
24 plan cycle to give the retail utility the certainty to
25 design program plan proposals.
26 (4) Upon a customer's election to opt out under
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1 paragraphs (1) and (2) of this subsection (l) and
2 commencing on the effective date of said opt out, the
3 account properly identified in the customer's notice under
4 paragraph (2) shall not be subject to any cost recovery
5 and shall not be eligible to participate in, or directly
6 benefit from, compliance with energy efficiency cumulative
7 persisting savings requirements under subsections (a)
8 through (j).
9 (5) A utility's cumulative persisting annual savings
10 targets will exclude any opted out load.
11 (6) The request to opt out is only valid for the
12 requested plan cycle. An eligible large private energy
13 customer must also request to opt out for future energy
14 plan cycles, otherwise the customer will be included in
15 the future energy plan cycle.
16 (m) Notwithstanding the requirements of this Section, as
17 part of a proceeding to approve a multi-year plan under
18 subsections (f) and (g) of this Section if the multi-year plan
19 has been designed to maximize savings, but does not meet the
20 cost cap limitations of this Section, the Commission shall
21 reduce the amount of energy efficiency measures implemented
22 for any single year, and whose costs are recovered under
23 subsection (d) of this Section, by an amount necessary to
24 limit the estimated average net increase due to the cost of the
25 measures to no more than
26 (1) 3.5% for each of the 4 years beginning January 1,
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1 2018,
2 (2) (blank),
3 (3) 4% for each of the 4 years beginning January 1,
4 2022,
5 (4) 4.25% for the 4 years beginning January 1, 2026,
6 and
7 (5) 4.25% plus an increase sufficient to account for
8 the rate of inflation between January 1, 2026 and January
9 1 of the first year of each subsequent 4-year plan cycle,
10 of the average amount paid per kilowatthour by residential
11 eligible retail customers during calendar year 2015. An
12 electric utility may plan to spend up to 10% more in any year
13 during an applicable multi-year plan period to
14 cost-effectively achieve additional savings so long as the
15 average over the applicable multi-year plan period does not
16 exceed the percentages defined in items (1) through (5). To
17 determine the total amount that may be spent by an electric
18 utility in any single year, the applicable percentage of the
19 average amount paid per kilowatthour shall be multiplied by
20 the total amount of energy delivered by such electric utility
21 in the calendar year 2015, adjusted to reflect the proportion
22 of the utility's load attributable to customers that have
23 opted out of subsections (a) through (j) of this Section under
24 subsection (l) of this Section. For purposes of this
25 subsection (m), the amount paid per kilowatthour includes,
26 without limitation, estimated amounts paid for supply,
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1 transmission, distribution, surcharges, and add-on taxes. For
2 purposes of this Section, "eligible retail customers" shall
3 have the meaning set forth in Section 16-111.5 of this Act.
4 Once the Commission has approved a plan under subsections (f)
5 and (g) of this Section, no subsequent rate impact
6 determinations shall be made.
7 (n) A utility shall take advantage of the efficiencies
8 available through existing Illinois Home Weatherization
9 Assistance Program infrastructure and services, such as
10 enrollment, marketing, quality assurance and implementation,
11 which can reduce the need for similar services at a lower cost
12 than utility-only programs, subject to capacity constraints at
13 community action agencies, for both single-family and
14 multifamily weatherization services, to the extent Illinois
15 Home Weatherization Assistance Program community action
16 agencies provide multifamily services. A utility's plan shall
17 demonstrate that in formulating annual weatherization budgets,
18 it has sought input and coordination with community action
19 agencies regarding agencies' capacity to expand and maximize
20 Illinois Home Weatherization Assistance Program delivery using
21 the ratepayer dollars collected under this Section.
22 (Source: P.A. 102-662, eff. 9-15-21; 103-154, eff. 6-30-23.)
23 (220 ILCS 5/16-107.5)
24 Sec. 16-107.5. Net electricity metering.
25 (a) The General Assembly finds and declares that a program
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1 to provide net electricity metering, as defined in this
2 Section, for eligible customers can encourage private
3 investment in renewable energy resources, stimulate economic
4 growth, enhance the continued diversification of Illinois'
5 energy resource mix, and protect the Illinois environment.
6 Further, to achieve the goals of this Act that robust options
7 for customer-site distributed generation continue to thrive in
8 Illinois, the General Assembly finds that a predictable
9 transition must be ensured for customers between full net
10 metering at the retail electricity rate to the distribution
11 generation rebate described in Section 16-107.6.
12 (b) As used in this Section, (i) "community renewable
13 generation project" shall have the meaning set forth in
14 Section 1-10 of the Illinois Power Agency Act; (ii) "eligible
15 customer" means a retail customer that owns, hosts, or
16 operates, including any third-party owned systems, a solar,
17 wind, or other eligible renewable electrical generating
18 facility that is located on the customer's premises or
19 customer's side of the billing meter and is intended primarily
20 to offset the customer's own current or future electrical
21 requirements; (iii) "electricity provider" means an electric
22 utility or alternative retail electric supplier; (iv)
23 "eligible renewable electrical generating facility" means a
24 generator, which may include the co-location of an energy
25 storage system, that is interconnected under rules adopted by
26 the Commission and is powered by solar electric energy, wind,
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1 dedicated crops grown for electricity generation, agricultural
2 residues, untreated and unadulterated wood waste, livestock
3 manure, anaerobic digestion of livestock or food processing
4 waste, fuel cells or microturbines powered by renewable fuels,
5 or hydroelectric energy; (v) "net electricity metering" (or
6 "net metering") means the measurement, during the billing
7 period applicable to an eligible customer, of the net amount
8 of electricity supplied by an electricity provider to the
9 customer or provided to the electricity provider by the
10 customer or subscriber; (vi) "subscriber" shall have the
11 meaning as set forth in Section 1-10 of the Illinois Power
12 Agency Act; (vii) "subscription" shall have the meaning set
13 forth in Section 1-10 of the Illinois Power Agency Act; (viii)
14 "energy storage system" means commercially available
15 technology that is capable of absorbing energy and storing it
16 for a period of time for use at a later time, including, but
17 not limited to, electrochemical, thermal, and
18 electromechanical technologies, and may be interconnected
19 behind the customer's meter or interconnected behind its own
20 meter; and (ix) "future electrical requirements" means modeled
21 electrical requirements upon occupation of a new or vacant
22 property, and other reasonable expectations of future
23 electrical use, as well as, for occupied properties, a
24 reasonable approximation of the annual load of 2 electric
25 vehicles and, for non-electric heating customers, a reasonable
26 approximation of the incremental electric load associated with
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1 fuel switching. The approximations shall be applied to the
2 appropriate net metering tariff and do not need to be unique to
3 each individual eligible customer. The utility shall submit
4 these approximations to the Commission for review,
5 modification, and approval; and (x) "electricity provider" and
6 "electric utility" includes municipalities and municipal power
7 agencies as defined in Section 11-119.3-1 of the Illinois
8 Municipal Code and electric cooperatives as defined in Section
9 3-119 of this Act.
10 (c) A net metering facility shall be equipped with
11 metering equipment that can measure the flow of electricity in
12 both directions at the same rate.
13 (1) For eligible customers whose electric service has
14 not been declared competitive pursuant to Section 16-113
15 of this Act as of July 1, 2011 and whose electric delivery
16 service is provided and measured on a kilowatt-hour basis
17 and electric supply service is not provided based on
18 hourly pricing, this shall typically be accomplished
19 through use of a single, bi-directional meter. If the
20 eligible customer's existing electric revenue meter does
21 not meet this requirement, the electricity provider shall
22 arrange for the local electric utility or a meter service
23 provider to install and maintain a new revenue meter at
24 the electricity provider's expense, which may be the smart
25 meter described by subsection (b) of Section 16-108.5 of
26 this Act.
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1 (2) For eligible customers whose electric service has
2 not been declared competitive pursuant to Section 16-113
3 of this Act as of July 1, 2011 and whose electric delivery
4 service is provided and measured on a kilowatt demand
5 basis and electric supply service is not provided based on
6 hourly pricing, this shall typically be accomplished
7 through use of a dual channel meter capable of measuring
8 the flow of electricity both into and out of the
9 customer's facility at the same rate and ratio. If such
10 customer's existing electric revenue meter does not meet
11 this requirement, then the electricity provider shall
12 arrange for the local electric utility or a meter service
13 provider to install and maintain a new revenue meter at
14 the electricity provider's expense, which may be the smart
15 meter described by subsection (b) of Section 16-108.5 of
16 this Act.
17 (3) For all other eligible customers, until such time
18 as the local electric utility installs a smart meter, as
19 described by subsection (b) of Section 16-108.5 of this
20 Act, the electricity provider may arrange for the local
21 electric utility or a meter service provider to install
22 and maintain metering equipment capable of measuring the
23 flow of electricity both into and out of the customer's
24 facility at the same rate and ratio, typically through the
25 use of a dual channel meter. If the eligible customer's
26 existing electric revenue meter does not meet this
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1 requirement, then the costs of installing such equipment
2 shall be paid for by the customer.
3 (d) An electricity provider shall measure and charge or
4 credit for the net electricity supplied to eligible customers
5 or provided by eligible customers whose electric service has
6 not been declared competitive pursuant to Section 16-113 of
7 this Act as of July 1, 2011 and whose electric delivery service
8 is provided and measured on a kilowatt-hour basis and electric
9 supply service is not provided based on hourly pricing in the
10 following manner:
11 (1) If the amount of electricity used by the customer
12 during the billing period exceeds the amount of
13 electricity produced by the customer, the electricity
14 provider shall charge the customer for the net electricity
15 supplied to and used by the customer as provided in
16 subsection (e-5) of this Section.
17 (2) If the amount of electricity produced by a
18 customer during the billing period exceeds the amount of
19 electricity used by the customer during that billing
20 period, the electricity provider supplying that customer
21 shall apply a 1:1 kilowatt-hour credit to a subsequent
22 bill for service to the customer for the net electricity
23 supplied to the electricity provider. The electricity
24 provider shall continue to carry over any excess
25 kilowatt-hour credits earned and apply those credits to
26 subsequent billing periods to offset any
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1 customer-generator consumption in those billing periods
2 until all credits are used or until the end of the
3 annualized period.
4 (3) At the end of the year or annualized over the
5 period that service is supplied by means of net metering,
6 or in the event that the retail customer terminates
7 service with the electricity provider prior to the end of
8 the year or the annualized period, any remaining credits
9 in the customer's account shall expire.
10 (d-5) An electricity provider shall measure and charge or
11 credit for the net electricity supplied to eligible customers
12 or provided by eligible customers whose electric service has
13 not been declared competitive pursuant to Section 16-113 of
14 this Act as of July 1, 2011 and whose electric delivery service
15 is provided and measured on a kilowatt-hour basis and electric
16 supply service is provided based on hourly pricing or
17 time-of-use rates in the following manner:
18 (1) If the amount of electricity used by the customer
19 during any hourly period or time-of-use period exceeds the
20 amount of electricity produced by the customer, the
21 electricity provider shall charge the customer for the net
22 electricity supplied to and used by the customer according
23 to the terms of the contract or tariff to which the same
24 customer would be assigned to or be eligible for if the
25 customer was not a net metering customer.
26 (2) If the amount of electricity produced by a
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1 customer during any hourly period or time-of-use period
2 exceeds the amount of electricity used by the customer
3 during that hourly period or time-of-use period, the
4 energy provider shall apply a credit for the net
5 kilowatt-hours produced in such period. The credit shall
6 consist of an energy credit and a delivery service credit.
7 The energy credit shall be valued at the same price per
8 kilowatt-hour as the electric service provider would
9 charge for kilowatt-hour energy sales during that same
10 hourly period or time-of-use period. The delivery credit
11 shall be equal to the net kilowatt-hours produced in such
12 hourly period or time-of-use period times a credit that
13 reflects all kilowatt-hour based charges in the customer's
14 electric service rate, excluding energy charges.
15 (e) An electricity provider shall measure and charge or
16 credit for the net electricity supplied to eligible customers
17 whose electric service has not been declared competitive
18 pursuant to Section 16-113 of this Act as of July 1, 2011 and
19 whose electric delivery service is provided and measured on a
20 kilowatt demand basis and electric supply service is not
21 provided based on hourly pricing in the following manner:
22 (1) If the amount of electricity used by the customer
23 during the billing period exceeds the amount of
24 electricity produced by the customer, then the electricity
25 provider shall charge the customer for the net electricity
26 supplied to and used by the customer as provided in
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1 subsection (e-5) of this Section. The customer shall
2 remain responsible for all taxes, fees, and utility
3 delivery charges that would otherwise be applicable to the
4 net amount of electricity used by the customer.
5 (2) If the amount of electricity produced by a
6 customer during the billing period exceeds the amount of
7 electricity used by the customer during that billing
8 period, then the electricity provider supplying that
9 customer shall apply a 1:1 kilowatt-hour credit that
10 reflects the kilowatt-hour based charges in the customer's
11 electric service rate to a subsequent bill for service to
12 the customer for the net electricity supplied to the
13 electricity provider. The electricity provider shall
14 continue to carry over any excess kilowatt-hour credits
15 earned and apply those credits to subsequent billing
16 periods to offset any customer-generator consumption in
17 those billing periods until all credits are used or until
18 the end of the annualized period.
19 (3) At the end of the year or annualized over the
20 period that service is supplied by means of net metering,
21 or in the event that the retail customer terminates
22 service with the electricity provider prior to the end of
23 the year or the annualized period, any remaining credits
24 in the customer's account shall expire.
25 (e-5) An electricity provider shall provide electric
26 service to eligible customers who utilize net metering at
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1 non-discriminatory rates that are identical, with respect to
2 rate structure, retail rate components, and any monthly
3 charges, to the rates that the customer would be charged if not
4 a net metering customer. An electricity provider shall not
5 charge net metering customers any fee or charge or require
6 additional equipment, insurance, or any other requirements not
7 specifically authorized by interconnection standards
8 authorized by the Commission, unless the fee, charge, or other
9 requirement would apply to other similarly situated customers
10 who are not net metering customers. The customer will remain
11 responsible for all taxes, fees, and utility delivery charges
12 that would otherwise be applicable to the net amount of
13 electricity used by the customer. Subsections (c) through (e)
14 of this Section shall not be construed to prevent an
15 arms-length agreement between an electricity provider and an
16 eligible customer that sets forth different prices, terms, and
17 conditions for the provision of net metering service,
18 including, but not limited to, the provision of the
19 appropriate metering equipment for non-residential customers.
20 (f) Notwithstanding the requirements of subsections (c)
21 through (e-5) of this Section, an electricity provider must
22 require dual-channel metering for customers operating eligible
23 renewable electrical generating facilities to whom the
24 provisions of neither subsection (d), (d-5), nor (e) of this
25 Section apply. In such cases, electricity charges and credits
26 shall be determined as follows:
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1 (1) The electricity provider shall assess and the
2 customer remains responsible for all taxes, fees, and
3 utility delivery charges that would otherwise be
4 applicable to the gross amount of kilowatt-hours supplied
5 to the eligible customer by the electricity provider.
6 (2) Each month that service is supplied by means of
7 dual-channel metering, the electricity provider shall
8 compensate the eligible customer for any excess
9 kilowatt-hour credits at the electricity provider's
10 avoided cost of electricity supply over the monthly period
11 or as otherwise specified by the terms of a power-purchase
12 agreement negotiated between the customer and electricity
13 provider.
14 (3) For all eligible net metering customers taking
15 service from an electricity provider under contracts or
16 tariffs employing hourly or time-of-use rates, any monthly
17 consumption of electricity shall be calculated according
18 to the terms of the contract or tariff to which the same
19 customer would be assigned to or be eligible for if the
20 customer was not a net metering customer. When those same
21 customer-generators are net generators during any discrete
22 hourly or time-of-use period, the net kilowatt-hours
23 produced shall be valued at the same price per
24 kilowatt-hour as the electric service provider would
25 charge for retail kilowatt-hour sales during that same
26 time-of-use period.
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1 (g) For purposes of federal and State laws providing
2 renewable energy credits or greenhouse gas credits, the
3 eligible customer shall be treated as owning and having title
4 to the renewable energy attributes, renewable energy credits,
5 and greenhouse gas emission credits related to any electricity
6 produced by the qualified generating unit. The electricity
7 provider may not condition participation in a net metering
8 program on the signing over of a customer's renewable energy
9 credits; provided, however, this subsection (g) shall not be
10 construed to prevent an arms-length agreement between an
11 electricity provider and an eligible customer that sets forth
12 the ownership or title of the credits.
13 (h) Within 120 days after the effective date of this
14 amendatory Act of the 95th General Assembly, the Commission
15 shall establish standards for net metering and, if the
16 Commission has not already acted on its own initiative,
17 standards for the interconnection of eligible renewable
18 generating equipment to the utility system. The
19 interconnection standards shall address any procedural
20 barriers, delays, and administrative costs associated with the
21 interconnection of customer-generation while ensuring the
22 safety and reliability of the units and the electric utility
23 system. The Commission shall consider the Institute of
24 Electrical and Electronics Engineers (IEEE) Standard 1547 and
25 the issues of (i) reasonable and fair fees and costs, (ii)
26 clear timelines for major milestones in the interconnection
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1 process, (iii) nondiscriminatory terms of agreement, and (iv)
2 any best practices for interconnection of distributed
3 generation.
4 (h-5) Within 90 days after the effective date of this
5 amendatory Act of the 102nd General Assembly, the Commission
6 shall:
7 (1) establish an Interconnection Working Group. The
8 working group shall include representatives from electric
9 utilities, developers of renewable electric generating
10 facilities, other industries that regularly apply for
11 interconnection with the electric utilities,
12 representatives of distributed generation customers, the
13 Commission Staff, and such other stakeholders with a
14 substantial interest in the topics addressed by the
15 Interconnection Working Group. The Interconnection Working
16 Group shall address at least the following issues:
17 (A) cost and best available technology for
18 interconnection and metering, including the
19 standardization and publication of standard costs;
20 (B) transparency, accuracy and use of the
21 distribution interconnection queue and hosting
22 capacity maps;
23 (C) distribution system upgrade cost avoidance
24 through use of advanced inverter functions;
25 (D) predictability of the queue management process
26 and enforcement of timelines;
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1 (E) benefits and challenges associated with group
2 studies and cost sharing;
3 (F) minimum requirements for application to the
4 interconnection process and throughout the
5 interconnection process to avoid queue clogging
6 behavior;
7 (G) process and customer service for
8 interconnecting customers adopting distributed energy
9 resources, including energy storage;
10 (H) options for metering distributed energy
11 resources, including energy storage;
12 (I) interconnection of new technologies, including
13 smart inverters and energy storage;
14 (J) collect, share, and examine data on Level 1
15 interconnection costs, including cost and type of
16 upgrades required for interconnection, and use this
17 data to inform the final standardized cost of Level 1
18 interconnection; and
19 (K) such other technical, policy, and tariff
20 issues related to and affecting interconnection
21 performance and customer service as determined by the
22 Interconnection Working Group.
23 The Commission may create subcommittees of the
24 Interconnection Working Group to focus on specific issues
25 of importance, as appropriate. The Interconnection Working
26 Group shall report to the Commission on recommended
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1 improvements to interconnection rules and tariffs and
2 policies as determined by the Interconnection Working
3 Group at least every 6 months. Such reports shall include
4 consensus recommendations of the Interconnection Working
5 Group and, if applicable, additional recommendations for
6 which consensus was not reached. The Commission shall use
7 the report from the Interconnection Working Group to
8 determine whether processes should be commenced to
9 formally codify or implement the recommendations;
10 (2) create or contract for an Ombudsman to resolve
11 interconnection disputes through non-binding arbitration.
12 The Ombudsman may be paid in full or in part through fees
13 levied on the initiators of the dispute; and
14 (3) determine a single standardized cost for Level 1
15 interconnections, which shall not exceed $200.
16 (i) All electricity providers shall begin to offer net
17 metering no later than April 1, 2008.
18 (j) An electricity provider shall provide net metering to
19 eligible customers according to subsections (d), (d-5), and
20 (e). Eligible renewable electrical generating facilities for
21 which eligible customers registered for net metering before
22 January 1, 2025 shall continue to receive net metering
23 services according to subsections (d), (d-5), and (e) of this
24 Section for the lifetime of the system, regardless of whether
25 those retail customers change electricity providers or whether
26 the retail customer benefiting from the system changes. On and
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1 after January 1, 2025, any eligible customer that applies for
2 net metering and previously would have qualified under
3 subsections (d), (d-5), or (e) shall only be eligible for net
4 metering as described in subsection (n).
5 (k) Each electricity provider shall maintain records and
6 report annually to the Commission the total number of net
7 metering customers served by the provider, as well as the
8 type, capacity, and energy sources of the generating systems
9 used by the net metering customers. Nothing in this Section
10 shall limit the ability of an electricity provider to request
11 the redaction of information deemed by the Commission to be
12 confidential business information.
13 (l)(1) Notwithstanding the definition of "eligible
14 customer" in item (ii) of subsection (b) of this Section, each
15 electricity provider shall allow net metering as set forth in
16 this subsection (l) and for the following projects, provided
17 that only electric utilities serving more than 200,000
18 customers as of January 1, 2021 shall provide net metering for
19 projects that are eligible for subparagraph (C) of this
20 paragraph (1) and have energized after the effective date of
21 this amendatory Act of the 102nd General Assembly:
22 (A) properties owned or leased by multiple customers
23 that contribute to the operation of an eligible renewable
24 electrical generating facility through an ownership or
25 leasehold interest of at least 200 watts in such facility,
26 such as a community-owned wind project, a community-owned
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1 biomass project, a community-owned solar project, or a
2 community methane digester processing livestock waste from
3 multiple sources, provided that the facility is also
4 located within the utility's service territory;
5 (B) individual units, apartments, or properties
6 located in a single building that are owned or leased by
7 multiple customers and collectively served by a common
8 eligible renewable electrical generating facility, such as
9 an office or apartment building, a shopping center or
10 strip mall served by photovoltaic panels on the roof; and
11 (C) subscriptions to community renewable generation
12 projects, including community renewable generation
13 projects on the customer's side of the billing meter of a
14 host facility and partially used for the customer's own
15 load.
16 In addition, the nameplate capacity of the eligible
17 renewable electric generating facility that serves the demand
18 of the properties, units, or apartments identified in
19 paragraphs (1) and (2) of this subsection (l) shall not exceed
20 5,000 kilowatts in nameplate capacity in total. Any eligible
21 renewable electrical generating facility or community
22 renewable generation project that is powered by photovoltaic
23 electric energy and installed after the effective date of this
24 amendatory Act of the 99th General Assembly must be installed
25 by a qualified person in compliance with the requirements of
26 Section 16-128A of the Public Utilities Act and any rules or
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1 regulations adopted thereunder.
2 (2) Notwithstanding anything to the contrary, an
3 electricity provider shall provide credits for the electricity
4 produced by the projects described in paragraph (1) of this
5 subsection (l). The electricity provider shall provide credits
6 that include at least energy supply, capacity, transmission,
7 and, if applicable, the purchased energy adjustment on the
8 subscriber's monthly bill equal to the subscriber's share of
9 the production of electricity from the project, as determined
10 by paragraph (3) of this subsection (l). For customers with
11 transmission or capacity charges not charged on a
12 kilowatt-hour basis, the electricity provider shall prepare a
13 reasonable approximation of the kilowatt-hour equivalent value
14 and provide that value as a monetary credit. The electricity
15 provider shall submit these approximation methodologies to the
16 Commission for review, modification, and approval.
17 Notwithstanding anything to the contrary, customers on payment
18 plans or participating in budget billing programs shall have
19 credits applied on a monthly basis.
20 (3) Notwithstanding anything to the contrary and
21 regardless of whether a subscriber to an eligible community
22 renewable generation project receives power and energy service
23 from the electric utility or an alternative retail electric
24 supplier, for projects eligible under paragraph (C) of
25 subparagraph (1) of this subsection (l), electric utilities
26 serving more than 200,000 customers as of January 1, 2021
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1 shall provide the monetary credits to a subscriber's
2 subsequent bill for the electricity produced by community
3 renewable generation projects. The electric utility shall
4 provide monetary credits to a subscriber's subsequent bill at
5 the utility's total price to compare equal to the subscriber's
6 share of the production of electricity from the project, as
7 determined by paragraph (5) of this subsection (l). For the
8 purposes of this subsection, "total price to compare" means
9 the rate or rates published by the Illinois Commerce
10 Commission for energy supply for eligible customers receiving
11 supply service from the electric utility, and shall include
12 energy, capacity, transmission, and the purchased energy
13 adjustment. Notwithstanding anything to the contrary,
14 customers on payment plans or participating in budget billing
15 programs shall have credits applied on a monthly basis. Any
16 applicable credit or reduction in load obligation from the
17 production of the community renewable generating projects
18 receiving a credit under this subsection shall be credited to
19 the electric utility to offset the cost of providing the
20 credit. To the extent that the credit or load obligation
21 reduction does not completely offset the cost of providing the
22 credit to subscribers of community renewable generation
23 projects as described in this subsection, the electric utility
24 may recover the remaining costs through its Multi-Year Rate
25 Plan. All electric utilities serving 200,000 or fewer
26 customers as of January 1, 2021 shall only provide the
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1 monetary credits to a subscriber's subsequent bill for the
2 electricity produced by community renewable generation
3 projects if the subscriber receives power and energy service
4 from the electric utility. Alternative retail electric
5 suppliers providing power and energy service to a subscriber
6 located within the service territory of an electric utility
7 not subject to Sections 16-108.18 and 16-118 shall provide the
8 monetary credits to the subscriber's subsequent bill for the
9 electricity produced by community renewable generation
10 projects.
11 (4) If requested by the owner or operator of a community
12 renewable generating project, an electric utility serving more
13 than 200,000 customers as of January 1, 2021 shall enter into a
14 net crediting agreement with the owner or operator to include
15 a subscriber's subscription fee on the subscriber's monthly
16 electric bill and provide the subscriber with a net credit
17 equivalent to the total bill credit value for that generation
18 period minus the subscription fee, provided the subscription
19 fee is structured as a fixed percentage of bill credit value.
20 The net crediting agreement shall set forth payment terms from
21 the electric utility to the owner or operator of the community
22 renewable generating project, and the electric utility may
23 charge a net crediting fee to the owner or operator of a
24 community renewable generating project that may not exceed 2%
25 of the bill credit value. Notwithstanding anything to the
26 contrary, an electric utility serving 200,000 customers or
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1 fewer as of January 1, 2021 shall not be obligated to enter
2 into a net crediting agreement with the owner or operator of a
3 community renewable generating project.
4 (5) For the purposes of facilitating net metering, the
5 owner or operator of the eligible renewable electrical
6 generating facility or community renewable generation project
7 shall be responsible for determining the amount of the credit
8 that each customer or subscriber participating in a project
9 under this subsection (l) is to receive in the following
10 manner:
11 (A) The owner or operator shall, on a monthly basis,
12 provide to the electric utility the kilowatthours of
13 generation attributable to each of the utility's retail
14 customers and subscribers participating in projects under
15 this subsection (l) in accordance with the customer's or
16 subscriber's share of the eligible renewable electric
17 generating facility's or community renewable generation
18 project's output of power and energy for such month. The
19 owner or operator shall electronically transmit such
20 calculations and associated documentation to the electric
21 utility, in a format or method set forth in the applicable
22 tariff, on a monthly basis so that the electric utility
23 can reflect the monetary credits on customers' and
24 subscribers' electric utility bills. The electric utility
25 shall be permitted to revise its tariffs to implement the
26 provisions of this amendatory Act of the 102nd General
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1 Assembly. The owner or operator shall separately provide
2 the electric utility with the documentation detailing the
3 calculations supporting the credit in the manner set forth
4 in the applicable tariff.
5 (B) For those participating customers and subscribers
6 who receive their energy supply from an alternative retail
7 electric supplier, the electric utility shall remit to the
8 applicable alternative retail electric supplier the
9 information provided under subparagraph (A) of this
10 paragraph (3) for such customers and subscribers in a
11 manner set forth in such alternative retail electric
12 supplier's net metering program, or as otherwise agreed
13 between the utility and the alternative retail electric
14 supplier. The alternative retail electric supplier shall
15 then submit to the utility the amount of the charges for
16 power and energy to be applied to such customers and
17 subscribers, including the amount of the credit associated
18 with net metering.
19 (C) A participating customer or subscriber may provide
20 authorization as required by applicable law that directs
21 the electric utility to submit information to the owner or
22 operator of the eligible renewable electrical generating
23 facility or community renewable generation project to
24 which the customer or subscriber has an ownership or
25 leasehold interest or a subscription. Such information
26 shall be limited to the components of the net metering
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1 credit calculated under this subsection (l), including the
2 bill credit rate, total kilowatthours, and total monetary
3 credit value applied to the customer's or subscriber's
4 bill for the monthly billing period.
5 (l-5) Within 90 days after the effective date of this
6 amendatory Act of the 102nd General Assembly, each electric
7 utility subject to this Section shall file a tariff or tariffs
8 to implement the provisions of subsection (l) of this Section,
9 which shall, consistent with the provisions of subsection (l),
10 describe the terms and conditions under which owners or
11 operators of qualifying properties, units, or apartments may
12 participate in net metering. The Commission shall approve, or
13 approve with modification, the tariff within 120 days after
14 the effective date of this amendatory Act of the 102nd General
15 Assembly.
16 (m) Nothing in this Section shall affect the right of an
17 electricity provider to continue to provide, or the right of a
18 retail customer to continue to receive service pursuant to a
19 contract for electric service between the electricity provider
20 and the retail customer in accordance with the prices, terms,
21 and conditions provided for in that contract. Either the
22 electricity provider or the customer may require compliance
23 with the prices, terms, and conditions of the contract.
24 (n) On and after January 1, 2025, the net metering
25 services described in subsections (d), (d-5), and (e) of this
26 Section shall no longer be offered, except as to those
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1 eligible renewable electrical generating facilities for which
2 retail customers are receiving net metering service under
3 these subsections at the time the net metering services under
4 those subsections are no longer offered; those systems shall
5 continue to receive net metering services described in
6 subsections (d), (d-5), and (e) of this Section for the
7 lifetime of the system, regardless of if those retail
8 customers change electricity providers or whether the retail
9 customer benefiting from the system changes. The electric
10 utility serving more than 200,000 customers as of January 1,
11 2021 is responsible for ensuring the billing credits continue
12 without lapse for the lifetime of systems, as required in
13 subsection (o). Those retail customers that begin taking net
14 metering service after the date that net metering services are
15 no longer offered under such subsections shall be subject to
16 the provisions set forth in the following paragraphs (1)
17 through (3) of this subsection (n):
18 (1) An electricity provider shall charge or credit for
19 the net electricity supplied to eligible customers or
20 provided by eligible customers whose electric supply
21 service is not provided based on hourly pricing in the
22 following manner:
23 (A) If the amount of electricity used by the
24 customer during the monthly billing period exceeds the
25 amount of electricity produced by the customer, then
26 the electricity provider shall charge the customer for
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1 the net kilowatt-hour based electricity charges
2 reflected in the customer's electric service rate
3 supplied to and used by the customer as provided in
4 paragraph (3) of this subsection (n).
5 (B) If the amount of electricity produced by a
6 customer during the monthly billing period exceeds the
7 amount of electricity used by the customer during that
8 billing period, then the electricity provider
9 supplying that customer shall apply a 1:1
10 kilowatt-hour energy or monetary credit kilowatt-hour
11 supply charges to the customer's subsequent bill. The
12 customer shall choose between 1:1 kilowatt-hour or
13 monetary credit at the time of application. For the
14 purposes of this subsection, "kilowatt-hour supply
15 charges" means the kilowatt-hour equivalent values for
16 energy, capacity, transmission, and the purchased
17 energy adjustment, if applicable. Notwithstanding
18 anything to the contrary, customers on payment plans
19 or participating in budget billing programs shall have
20 credits applied on a monthly basis. The electricity
21 provider shall continue to carry over any excess
22 kilowatt-hour or monetary energy credits earned and
23 apply those credits to subsequent billing periods. For
24 customers with transmission or capacity charges not
25 charged on a kilowatt-hour basis, the electricity
26 provider shall prepare a reasonable approximation of
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1 the kilowatt-hour equivalent value and provide that
2 value as a monetary credit. The electricity provider
3 shall submit these approximation methodologies to the
4 Commission for review, modification, and approval.
5 (C) (Blank).
6 (2) An electricity provider shall charge or credit for
7 the net electricity supplied to eligible customers or
8 provided by eligible customers whose electric supply
9 service is provided based on hourly pricing in the
10 following manner:
11 (A) If the amount of electricity used by the
12 customer during any hourly period exceeds the amount
13 of electricity produced by the customer, then the
14 electricity provider shall charge the customer for the
15 net electricity supplied to and used by the customer
16 as provided in paragraph (3) of this subsection (n).
17 (B) If the amount of electricity produced by a
18 customer during any hourly period exceeds the amount
19 of electricity used by the customer during that hourly
20 period, the energy provider shall calculate an energy
21 credit for the net kilowatt-hours produced in such
22 period, and shall apply that credit as a monetary
23 credit to the customer's subsequent bill. The value of
24 the energy credit shall be calculated using the same
25 price per kilowatt-hour as the electric service
26 provider would charge for kilowatt-hour energy sales
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1 during that same hourly period and shall also include
2 values for capacity and transmission. For customers
3 with transmission or capacity charges not charged on a
4 kilowatt-hour basis, the electricity provider shall
5 prepare a reasonable approximation of the
6 kilowatt-hour equivalent value and provide that value
7 as a monetary credit. The electricity provider shall
8 submit these approximation methodologies to the
9 Commission for review, modification, and approval.
10 Notwithstanding anything to the contrary, customers on
11 payment plans or participating in budget billing
12 programs shall have credits applied on a monthly
13 basis.
14 (3) An electricity provider shall provide electric
15 service to eligible customers who utilize net metering at
16 non-discriminatory rates that are identical, with respect
17 to rate structure, retail rate components, and any monthly
18 charges, to the rates that the customer would be charged
19 if not a net metering customer. An electricity provider
20 shall charge the customer for the net electricity supplied
21 to and used by the customer according to the terms of the
22 contract or tariff to which the same customer would be
23 assigned or be eligible for if the customer was not a net
24 metering customer. An electricity provider shall not
25 charge net metering customers any fee or charge or require
26 additional equipment, insurance, or any other requirements
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1 not specifically authorized by interconnection standards
2 authorized by the Commission, unless the fee, charge, or
3 other requirement would apply to other similarly situated
4 customers who are not net metering customers. The customer
5 remains responsible for the gross amount of delivery
6 services charges, supply-related charges that are kilowatt
7 based, and all taxes and fees related to such charges. The
8 customer also remains responsible for all taxes and fees
9 that would otherwise be applicable to the net amount of
10 electricity used by the customer. Paragraphs (1) and (2)
11 of this subsection (n) shall not be construed to prevent
12 an arms-length agreement between an electricity provider
13 and an eligible customer that sets forth different prices,
14 terms, and conditions for the provision of net metering
15 service, including, but not limited to, the provision of
16 the appropriate metering equipment for non-residential
17 customers. Nothing in this paragraph (3) shall be
18 interpreted to mandate that a utility that is only
19 required to provide delivery services to a given customer
20 must also sell electricity to such customer.
21 (o) Within 90 days after the effective date of this
22 amendatory Act of the 102nd General Assembly, each electric
23 utility subject to this Section shall file a tariff, which
24 shall, consistent with the provisions of this Section, propose
25 the terms and conditions under which a customer may
26 participate in net metering. The tariff for electric utilities
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1 serving more than 200,000 customers as of January 1, 2021
2 shall also provide a streamlined and transparent bill
3 crediting system for net metering to be managed by the
4 electric utilities. The terms and conditions shall include,
5 but are not limited to, that an electric utility shall manage
6 and maintain billing of net metering credits and charges
7 regardless of if the eligible customer takes net metering
8 under an electric utility or alternative retail electric
9 supplier. The electric utility serving more than 200,000
10 customers as of January 1, 2021 shall process and approve all
11 net metering applications, even if an eligible customer is
12 served by an alternative retail electric supplier; and the
13 utility shall forward application approval to the appropriate
14 alternative retail electric supplier. Eligibility for net
15 metering shall remain with the owner of the utility billing
16 address such that, if an eligible renewable electrical
17 generating facility changes ownership, the net metering
18 eligibility transfers to the new owner. The electric utility
19 serving more than 200,000 customers as of January 1, 2021
20 shall manage net metering billing for eligible customers to
21 ensure full crediting occurs on electricity bills, including,
22 but not limited to, ensuring net metering crediting begins
23 upon commercial operation date, net metering billing transfers
24 immediately if an eligible customer switches from an electric
25 utility to alternative retail electric supplier or vice versa,
26 and net metering billing transfers between ownership of a
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1 valid billing address. All transfers referenced in the
2 preceding sentence shall include transfer of all banked
3 credits. All electric utilities serving 200,000 or fewer
4 customers as of January 1, 2021 shall manage net metering
5 billing for eligible customers receiving power and energy
6 service from the electric utility to ensure full crediting
7 occurs on electricity bills, ensuring net metering crediting
8 begins upon commercial operation date, net metering billing
9 transfers immediately if an eligible customer switches from an
10 electric utility to alternative retail electric supplier or
11 vice versa, and net metering billing transfers between
12 ownership of a valid billing address. Alternative retail
13 electric suppliers providing power and energy service to
14 eligible customers located within the service territory of an
15 electric utility serving 200,000 or fewer customers as of
16 January 1, 2021 shall manage net metering billing for eligible
17 customers to ensure full crediting occurs on electricity
18 bills, including, but not limited to, ensuring net metering
19 crediting begins upon commercial operation date, net metering
20 billing transfers immediately if an eligible customer switches
21 from an electric utility to alternative retail electric
22 supplier or vice versa, and net metering billing transfers
23 between ownership of a valid billing address.
24 (Source: P.A. 102-662, eff. 9-15-21.)
25 (220 ILCS 5/16-107.8 new)
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1 Sec. 16-107.8. Residential time-of-use pricing.
2 (a) The General Assembly finds that time-of-use rates and
3 pricing plans can lower energy costs for consumers and reduce
4 grid costs as well as help the State achieve its energy policy
5 goals by improving load shape, encouraging energy
6 conservation, and shifting usage away from periods where
7 fossil fuels are used to meet peak demand. Further, by
8 providing consumers information relating the costs of service
9 to the time of energy usage, time-of-use rates can help
10 consumers reduce their energy bills by using electricity when
11 it is less costly. Time-of-use rates can help allocate
12 electricity system costs more accurately and thus equitably to
13 those who cause costs. Such rates can reduce the need for
14 ramping resources and increase the grid's ability to
15 cost-effectively integrate greater quantities of variable
16 renewable energy and distributed energy resources.
17 (b) An electric utility that has a tariff approved under
18 subsection (d) of Section 16-108.18 within one year of this
19 amendatory Act of the 103rd General Assembly shall also offer
20 at least one market-based, residential rate for eligible
21 retail customers that choose to take power and energy supply
22 service from the utility. If the utility has a pending request
23 for approval of a Multi-Year Integrated Grid Plan, the utility
24 shall update its filing in that docket to reflect the likely
25 impacts of the time-of-use rate offering. The utility shall
26 file its time-of-use rate tariff no later than 120 days after
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1 the effective date of this amendatory Act of the 103rd General
2 Assembly, and each utility subject to this requirement shall
3 implement the requirements of this subsection by filing a
4 tariff with the Commission. The tariff or tariffs shall be
5 subject to the following provisions:
6 (1) If more than one tariff is proposed, at least one
7 tariff shall include at least 3 time blocks: a peak time
8 block, defined as 2 p.m. to 7 p.m. on nonholiday weekdays
9 or the 5 consecutive hours best reflecting the highest
10 system peak demands; an off-peak time block, defined as 10
11 a.m. to 2 p.m. and 7 p.m. to 10 p.m. on nonholiday weekdays
12 or the 7 total hours occurring in some combination before
13 and after the peak period, which reflect the next highest
14 system peak demands; and a super-off-peak time block,
15 defined as all other hours and including weekend days.
16 (2) This tariff shall strive to achieve price ratios
17 between the blocks as follows: the super-off-peak time
18 block price shall be no less than zero but no greater than
19 one-half of the price of the off-peak time block price,
20 and the off-peak time block price shall be no greater than
21 one-half of the price of the peak time block price.
22 (3) The time-of-use rate shall include the costs of
23 electric capacity, costs of transmission services, and
24 charges for network integration transmission service,
25 transmission enhancement, and locational reliability, as
26 these terms are defined in the PJM Interconnection LLC
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1 Open Access Transmission Tariff and manuals on January 1,
2 2019, within the prices for each time block and seasonal
3 block in which the associated costs generally are
4 incurred. If the Open Access Transmission Tariff or
5 manuals subsequently renames those terms, the services
6 reflected under those terms shall continue to be included
7 in the time-of-use rate described in this paragraph.
8 (4) Adjustments to the charges set by the tariff may
9 be made on a semi-annual basis, as follows: each May and
10 November, the utility shall submit to the Commission,
11 through an informational filing, its updated charges, and
12 such charges shall take effect beginning with the June
13 monthly billing period and December monthly billing
14 period, respectively.
15 (5) The tariff shall include a purchased energy
16 adjustment to fully recover the supply costs for the
17 customers taking service under this tariff.
18 As used in this subsection, "eligible residential
19 customers" includes, but is not limited to, customers
20 participating in net electricity metering under the terms of
21 Section 16-107.5.
22 (c) The Commission shall, after notice and hearing,
23 approve the tariff or tariffs with modifications the
24 Commission finds necessary to improve the program design,
25 customer participation in the program, or coordination with
26 existing utility pricing programs, energy efficiency programs,
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1 demand-response programs, and any other programs supporting
2 State energy policy goals and the integration of distributed
3 energy resources. The Commission shall also consider how the
4 proposed time-of-use rate design reflects the system costs and
5 usage patterns of the utility. A proceeding under this
6 subsection may not exceed 120 days in length.
7 (d) If the Commission issues an order pursuant to this
8 subsection, the affected electric utility shall contract with
9 an entity not affiliated with the electric utility to serve as
10 a program administrator to develop and implement a program to
11 provide consumer outreach, enrollment, and education
12 concerning time-of-use pricing and to establish and administer
13 an information system and technical and other customer
14 assistance that is necessary to enable customers to manage
15 electricity use. The program administrator: (i) shall be
16 selected and compensated by the electric utility, subject to
17 Commission approval; (ii) shall have demonstrated technical
18 and managerial competence in the development and
19 administration of demand management programs; and (iii) may
20 develop and implement risk management, energy efficiency, and
21 other services related to energy use management for which the
22 program administrator shall be compensated by participants in
23 the program receiving such services. The electric utility
24 shall provide the program administrator with all information
25 and assistance necessary to perform the program
26 administrator's duties, including, but not limited to,
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1 customer, account, and energy use data. The electric utility
2 shall permit the program administrator to include inserts in
3 residential customer bills 2 times per year to assist with
4 customer outreach and enrollment. The program administrator
5 shall submit an annual report to the electric utility no later
6 than April 1 of each year describing the operation and results
7 of the program, including information concerning the number
8 and types of customers using the program, changes in
9 customers' energy use patterns, an assessment of the value of
10 the program to both participants and nonparticipants, and
11 recommendations concerning modification of the program and the
12 tariff or tariffs filed under this Section. This report shall
13 be filed by the electric utility with the Commission within 30
14 days after receipt and shall be available to the public on the
15 Commission's website.
16 (e) Once the tariff or tariffs has been in effect for 12
17 months, the Commission may, upon complaint, petition, or its
18 own initiative, open a proceeding to investigate whether
19 changes or modifications to the tariff or tariffs, program
20 administration and any other program design element is
21 necessary to achieve the goals described in subsection (a) and
22 to shifting usage away from periods where fossil fuels are
23 used to meet peak demand and realign usage to periods when
24 renewable generation is available. Such a proceeding may not
25 last more than 180 days from the date upon which the
26 investigation is opened by Commission order. Thereafter, the
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1 Commission may, upon complaint, petition, or its own
2 initiative, open a proceeding to investigate changes or
3 modifications to the tariff or tariffs at any time the
4 Commission deems reasonable in order to achieve these
5 objectives.
6 (f) An electric utility shall be entitled to recover
7 reasonable costs incurred in complying with this Section, if
8 the recovery of the costs is fairly apportioned among its
9 residential customers.
10 (g) The electric utility's tariff or tariffs filed
11 pursuant to this Section shall be subject to the provisions of
12 Article IX of this Act insofar as they do not conflict with
13 this Section.
14 (h) This Section does not apply to any electric utility
15 providing service to 100,000 or fewer customers.
16 (220 ILCS 5/16-111.5)
17 Sec. 16-111.5. Provisions relating to procurement.
18 (a) An electric utility that on December 31, 2005 served
19 at least 100,000 customers in Illinois shall procure power and
20 energy for its eligible retail customers in accordance with
21 the applicable provisions set forth in Section 1-75 of the
22 Illinois Power Agency Act and this Section. Beginning with the
23 delivery year commencing on June 1, 2017, such electric
24 utility shall also procure zero emission credits from zero
25 emission facilities in accordance with the applicable
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1 provisions set forth in Section 1-75 of the Illinois Power
2 Agency Act, and, for years beginning on or after June 1, 2017,
3 the utility shall procure renewable energy resources in
4 accordance with the applicable provisions set forth in Section
5 1-75 of the Illinois Power Agency Act and this Section.
6 Beginning with the delivery year commencing on June 1, 2022,
7 an electric utility serving over 3,000,000 customers shall
8 also procure carbon mitigation credits from carbon-free energy
9 resources in accordance with the applicable provisions set
10 forth in Section 1-75 of the Illinois Power Agency Act and this
11 Section. A small multi-jurisdictional electric utility that on
12 December 31, 2005 served less than 100,000 customers in
13 Illinois may elect to procure power and energy for all or a
14 portion of its eligible Illinois retail customers in
15 accordance with the applicable provisions set forth in this
16 Section and Section 1-75 of the Illinois Power Agency Act.
17 This Section shall not apply to a small multi-jurisdictional
18 utility until such time as a small multi-jurisdictional
19 utility requests the Illinois Power Agency to prepare a
20 procurement plan for its eligible retail customers. "Eligible
21 retail customers" for the purposes of this Section means those
22 retail customers that purchase power and energy from the
23 electric utility under fixed-price bundled service tariffs,
24 other than those retail customers whose service is declared or
25 deemed competitive under Section 16-113 and those other
26 customer groups specified in this Section, including
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1 self-generating customers, customers electing hourly pricing,
2 or those customers who are otherwise ineligible for
3 fixed-price bundled tariff service. For those customers that
4 are excluded from the procurement plan's electric supply
5 service requirements, and the utility shall procure any supply
6 requirements, including capacity, ancillary services, and
7 hourly priced energy, in the applicable markets as needed to
8 serve those customers, provided that the utility may include
9 in its procurement plan load requirements for the load that is
10 associated with those retail customers whose service has been
11 declared or deemed competitive pursuant to Section 16-113 of
12 this Act to the extent that those customers are purchasing
13 power and energy during one of the transition periods
14 identified in subsection (b) of Section 16-113 of this Act.
15 (b) A procurement plan shall be prepared for each electric
16 utility consistent with the applicable requirements of the
17 Illinois Power Agency Act and this Section. For purposes of
18 this Section, Illinois electric utilities that are affiliated
19 by virtue of a common parent company are considered to be a
20 single electric utility. Small multi-jurisdictional utilities
21 may request a procurement plan for a portion of or all of its
22 Illinois load. Each procurement plan shall analyze the
23 projected balance of supply and demand for those retail
24 customers to be included in the plan's electric supply service
25 requirements over a 5-year period, with the first planning
26 year beginning on June 1 of the year following the year in
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1 which the plan is filed. The plan shall specifically identify
2 the wholesale products to be procured following plan approval,
3 and shall follow all the requirements set forth in the Public
4 Utilities Act and all applicable State and federal laws,
5 statutes, rules, or regulations, as well as Commission orders.
6 Nothing in this Section precludes consideration of contracts
7 longer than 5 years and related forecast data. Unless
8 specified otherwise in this Section, in the procurement plan
9 or in the implementing tariff, any procurement occurring in
10 accordance with this plan shall be competitively bid through a
11 request for proposals process. Approval and implementation of
12 the procurement plan shall be subject to review and approval
13 by the Commission according to the provisions set forth in
14 this Section. A procurement plan shall include each of the
15 following components:
16 (1) Hourly load analysis. This analysis shall include:
17 (i) multi-year historical analysis of hourly
18 loads;
19 (ii) switching trends and competitive retail
20 market analysis;
21 (iii) known or projected changes to future loads;
22 and
23 (iv) growth forecasts by customer class.
24 (2) Analysis of the impact of any demand side and
25 renewable energy initiatives. This analysis shall include:
26 (i) the impact of demand response programs and
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1 energy efficiency programs, both current and
2 projected; for small multi-jurisdictional utilities,
3 the impact of demand response and energy efficiency
4 programs approved pursuant to Section 8-408 of this
5 Act, both current and projected; and
6 (ii) supply side needs that are projected to be
7 offset by purchases of renewable energy resources, if
8 any.
9 (3) A plan for meeting the expected load requirements
10 that will not be met through preexisting contracts. This
11 plan shall include:
12 (i) definitions of the different Illinois retail
13 customer classes for which supply is being purchased;
14 (ii) the proposed mix of demand-response products
15 for which contracts will be executed during the next
16 year. For small multi-jurisdictional electric
17 utilities that on December 31, 2005 served fewer than
18 100,000 customers in Illinois, these shall be defined
19 as demand-response products offered in an energy
20 efficiency plan approved pursuant to Section 8-408 of
21 this Act. The cost-effective demand-response measures
22 shall be procured whenever the cost is lower than
23 procuring comparable capacity products, provided that
24 such products shall:
25 (A) be procured by a demand-response provider
26 from those retail customers included in the plan's
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1 electric supply service requirements;
2 (B) at least satisfy the demand-response
3 requirements of the regional transmission
4 organization market in which the utility's service
5 territory is located, including, but not limited
6 to, any applicable capacity or dispatch
7 requirements;
8 (C) provide for customers' participation in
9 the stream of benefits produced by the
10 demand-response products;
11 (D) provide for reimbursement by the
12 demand-response provider of the utility for any
13 costs incurred as a result of the failure of the
14 supplier of such products to perform its
15 obligations thereunder; and
16 (E) meet the same credit requirements as apply
17 to suppliers of capacity, in the applicable
18 regional transmission organization market;
19 (iii) monthly forecasted system supply
20 requirements, including expected minimum, maximum, and
21 average values for the planning period;
22 (iv) the proposed mix and selection of standard
23 wholesale products for which contracts will be
24 executed during the next year, separately or in
25 combination, to meet that portion of its load
26 requirements not met through pre-existing contracts,
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1 including but not limited to monthly 5 x 16 peak period
2 block energy, monthly off-peak wrap energy, monthly 7
3 x 24 energy, annual 5 x 16 energy, other standardized
4 energy or capacity products designed to provide
5 eligible retail customer benefits from commercially
6 deployed advanced technologies including but not
7 limited to high voltage direct current converter
8 stations, as such term is defined in Section 1-10 of
9 the Illinois Power Agency Act, whether or not such
10 product is currently available in wholesale markets,
11 annual off-peak wrap energy, annual 7 x 24 energy,
12 monthly capacity, annual capacity, peak load capacity
13 obligations, capacity purchase plan, and ancillary
14 services; however, nothing in this item (iv) precludes
15 consideration of long-term contracts with a length up
16 to and including 20 years for clean energy, as defined
17 in Section 1-10 of the Illinois Power Agency Act, with
18 an appropriate portion of the portfolio to be
19 allocated to such long-term contracts;
20 (v) proposed term structures for each wholesale
21 product type included in the proposed procurement plan
22 portfolio of products; and
23 (vi) an assessment of the price risk, load
24 uncertainty, and other factors that are associated
25 with the proposed procurement plan; this assessment,
26 to the extent possible, shall include an analysis of
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1 the following factors: contract terms, time frames for
2 securing products or services, fuel costs, weather
3 patterns, transmission costs, market conditions, and
4 the governmental regulatory environment; the proposed
5 procurement plan shall also identify alternatives for
6 those portfolio measures that are identified as having
7 significant price risk and mitigation in the form of
8 additional retail customer and ratepayer price,
9 reliability, and environmental benefits from
10 standardized energy products delivered from
11 commercially deployed advanced technologies,
12 including, but not limited to, high voltage direct
13 current converter stations, as such term is defined in
14 Section 1-10 of the Illinois Power Agency Act, whether
15 or not such product is currently available in
16 wholesale markets; and.
17 (v) for procurement events beginning after May 31,
18 2025, consideration of whether products offered into
19 the procurement process are renewable energy
20 resources, as defined in Section 1-10 of the Illinois
21 Power Agency Act that might otherwise qualify for the
22 renewable portfolio standard described in
23 subparagraphs (c)(1)(I) and (c)(1)(J) of Section 1-75
24 of the Illinois Power Agency Act where such product or
25 products can be procured at or near the price of
26 nonrenewable energy after taking account of the social
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1 cost of carbon as set forth in subparagraph (B) of
2 paragraph (1) of subsection (d-5) of Section 1-75 of
3 the Illinois Power Agency Act. The Agency shall
4 consider fuel volatility, long-term trends in
5 non-renewable energy resource pricing, and the
6 environmental benefits of renewable energy resources
7 when comparing products and may, in doing so, select
8 products comprised of renewable energy resources that
9 are at a higher fixed price over a longer duration.
10 Each product procured shall include all environmental
11 attributes, including, but not limited to, and
12 renewable energy credits, all as defined in Section
13 1-10 of the Illinois Power Agency Act, and all
14 credits, characteristics, benefits, emissions
15 reductions, offsets, and allowances, howsoever
16 entitled, attributable to the generation of the
17 product procured or its displacement of generation.
18 (4) Proposed procedures for balancing loads. The
19 procurement plan shall include, for load requirements
20 included in the procurement plan, the process for (i)
21 hourly balancing of supply and demand and (ii) the
22 criteria for portfolio re-balancing in the event of
23 significant shifts in load.
24 (5) Long-Term Renewable Resources Procurement Plan.
25 The Agency shall prepare a long-term renewable resources
26 procurement plan for the procurement of renewable energy
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1 credits under Sections 1-56 and 1-75 of the Illinois Power
2 Agency Act for delivery beginning in the 2017 delivery
3 year.
4 (i) The initial long-term renewable resources
5 procurement plan and all subsequent revisions shall be
6 subject to review and approval by the Commission. For
7 the purposes of this Section, "delivery year" has the
8 same meaning as in Section 1-10 of the Illinois Power
9 Agency Act. For purposes of this Section, "Agency"
10 shall mean the Illinois Power Agency.
11 (ii) The long-term renewable resources planning
12 process shall be conducted as follows:
13 (A) Electric utilities shall provide a range
14 of load forecasts to the Illinois Power Agency
15 within 45 days of the Agency's request for
16 forecasts, which request shall specify the length
17 and conditions for the forecasts including, but
18 not limited to, the quantity of distributed
19 generation expected to be interconnected for each
20 year.
21 (B) The Agency shall publish for comment the
22 initial long-term renewable resources procurement
23 plan no later than 120 days after the effective
24 date of this amendatory Act of the 99th General
25 Assembly and shall review, and may revise, the
26 plan at least every 2 years thereafter. To the
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1 extent practicable, the Agency shall review and
2 propose any revisions to the long-term renewable
3 energy resources procurement plan in conjunction
4 with the Agency's other planning and approval
5 processes conducted under this Section. The
6 initial long-term renewable resources procurement
7 plan shall:
8 (aa) Identify the procurement programs and
9 competitive procurement events consistent with
10 the applicable requirements of the Illinois
11 Power Agency Act and shall be designed to
12 achieve the goals set forth in subsection (c)
13 of Section 1-75 of that Act.
14 (bb) Include a schedule for procurements
15 for renewable energy credits from
16 utility-scale wind projects, utility-scale
17 solar projects, and brownfield site
18 photovoltaic projects consistent with
19 subparagraph (G) of paragraph (1) of
20 subsection (c) of Section 1-75 of the Illinois
21 Power Agency Act.
22 (cc) Identify the process whereby the
23 Agency will submit to the Commission for
24 review and approval the proposed contracts to
25 implement the programs required by such plan.
26 Copies of the initial long-term renewable
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1 resources procurement plan and all subsequent
2 revisions shall be posted and made publicly
3 available on the Agency's and Commission's
4 websites, and copies shall also be provided to
5 each affected electric utility. An affected
6 utility and other interested parties shall have 45
7 days following the date of posting to provide
8 comment to the Agency on the initial long-term
9 renewable resources procurement plan and all
10 subsequent revisions. All comments submitted to
11 the Agency shall be specific, supported by data or
12 other detailed analyses, and, if objecting to all
13 or a portion of the procurement plan, accompanied
14 by specific alternative wording or proposals. All
15 comments shall be posted on the Agency's and
16 Commission's websites. During this 45-day comment
17 period, the Agency shall hold at least one public
18 hearing within each utility's service area that is
19 subject to the requirements of this paragraph (5)
20 for the purpose of receiving public comment.
21 Within 21 days following the end of the 45-day
22 review period, the Agency may revise the long-term
23 renewable resources procurement plan based on the
24 comments received and shall file the plan with the
25 Commission for review and approval.
26 (C) Within 14 days after the filing of the
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1 initial long-term renewable resources procurement
2 plan or any subsequent revisions, any person
3 objecting to the plan may file an objection with
4 the Commission. Within 21 days after the filing of
5 the plan, the Commission shall determine whether a
6 hearing is necessary. The Commission shall enter
7 its order confirming or modifying the initial
8 long-term renewable resources procurement plan or
9 any subsequent revisions within 120 days after the
10 filing of the plan by the Illinois Power Agency.
11 (D) The Commission shall approve the initial
12 long-term renewable resources procurement plan and
13 any subsequent revisions, including expressly the
14 forecast used in the plan and taking into account
15 that funding will be limited to the amount of
16 revenues actually collected by the utilities, if
17 the Commission determines that the plan will
18 reasonably and prudently accomplish the
19 requirements of Section 1-56 and subsection (c) of
20 Section 1-75 of the Illinois Power Agency Act. The
21 Commission shall also approve the process for the
22 submission, review, and approval of the proposed
23 contracts to procure renewable energy credits or
24 implement the programs authorized by the
25 Commission pursuant to a long-term renewable
26 resources procurement plan approved under this
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1 Section.
2 In approving any long-term renewable resources
3 procurement plan after the effective date of this
4 amendatory Act of the 102nd General Assembly, the
5 Commission shall approve or modify the Agency's
6 proposal for minimum equity standards pursuant to
7 subsection (c-10) of Section 1-75 of the Illinois
8 Power Agency Act. The Commission shall consider
9 any analysis performed by the Agency in developing
10 its proposal, including past performance,
11 availability of equity eligible contractors, and
12 availability of equity eligible persons at the
13 time the long-term renewable resources procurement
14 plan is approved.
15 (iii) The Agency or third parties contracted by
16 the Agency shall implement all programs authorized by
17 the Commission in an approved long-term renewable
18 resources procurement plan without further review and
19 approval by the Commission. Third parties shall not
20 begin implementing any programs or receive any payment
21 under this Section until the Commission has approved
22 the contract or contracts under the process authorized
23 by the Commission in item (D) of subparagraph (ii) of
24 paragraph (5) of this subsection (b) and the third
25 party and the Agency or utility, as applicable, have
26 executed the contract. For those renewable energy
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1 credits subject to procurement through a competitive
2 bid process under the plan or under the initial
3 forward procurements for wind and solar resources
4 described in subparagraph (G) of paragraph (1) of
5 subsection (c) of Section 1-75 of the Illinois Power
6 Agency Act, the Agency shall follow the procurement
7 process specified in the provisions relating to
8 electricity procurement in subsections (e) through (i)
9 of this Section.
10 (iv) An electric utility shall recover its costs
11 associated with the procurement of renewable energy
12 credits under this Section and pursuant to subsection
13 (c-5) of Section 1-75 of the Illinois Power Agency Act
14 through an automatic adjustment clause tariff under
15 subsection (k) or a tariff pursuant to subsection
16 (i-5), as applicable, of Section 16-108 of this Act. A
17 utility shall not be required to advance any payment
18 or pay any amounts under this Section that exceed the
19 actual amount of revenues collected by the utility
20 under paragraph (6) of subsection (c) of Section 1-75
21 of the Illinois Power Agency Act, subsection (c-5) of
22 Section 1-75 of the Illinois Power Agency Act, and
23 subsection (k) or subsection (i-5), as applicable, of
24 Section 16-108 of this Act, and contracts executed
25 under this Section shall expressly incorporate this
26 limitation.
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1 (v) For the public interest, safety, and welfare,
2 the Agency and the Commission may adopt rules to carry
3 out the provisions of this Section on an emergency
4 basis immediately following the effective date of this
5 amendatory Act of the 99th General Assembly.
6 (vi) On or before July 1 of each year, the
7 Commission shall hold an informal hearing for the
8 purpose of receiving comments on the prior year's
9 procurement process and any recommendations for
10 change.
11 (b-5) An electric utility that as of January 1, 2019
12 served more than 300,000 retail customers in this State shall
13 purchase renewable energy credits from new renewable energy
14 facilities constructed at or adjacent to the sites of
15 coal-fueled electric generating facilities in this State in
16 accordance with subsection (c-5) of Section 1-75 of the
17 Illinois Power Agency Act. Except as expressly provided in
18 this Section, the plans and procedures for such procurements
19 shall not be included in the procurement plans provided for in
20 this Section, but rather shall be conducted and implemented
21 solely in accordance with subsection (c-5) of Section 1-75 of
22 the Illinois Power Agency Act.
23 (b-10) Capacity procurement.
24 (1) Definitions. For purposes of this subsection:
25 "Applicable Local Resource Zone" means the Zone 4
26 Local Resource Zone as set forth in the MISO Business
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1 Practices Manual 011 - Resource Adequacy, or any future
2 successor zone for the same geographic space, as
3 designated by MISO governing documents.
4 "Applicable locational deliverability area" means the
5 ComEd Locational Deliverability Area as set forth in the
6 PJM Manual, or any future successor area for the same
7 geographic space, as designated by PJM governing
8 documents.
9 "Electric cooperative" has the meaning given to that
10 term in Section 3-119.
11 "Fixed Resource Adequacy Plan", "Local Clearing
12 Requirement", "Local Resource Zone", "Planning Resource",
13 and "Planning Reserve Margin Requirement" have the
14 meanings given to those terms in the MISO Tariff,
15 including as they may apply to individual Load Serving
16 Entities, as applicable. For avoidance of doubt, these
17 terms shall be interpreted as multiple seasonal values
18 within a given delivery year if MISO's then-prevailing
19 resource adequacy construct has a seasonal component.
20 "Load Serving Entity" has the meaning given to that
21 term by the regional transmission organization where the
22 entity serves customers, either in the Midcontinent
23 Independent System Operator Tariff or PJM Interconnection,
24 LLC Reliability Assurance Agreement.
25 (c) The provisions of this subsection (c) shall not apply
26 to procurements conducted pursuant to subsection (c-5) of
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1 Section 1-75 of the Illinois Power Agency Act. However, the
2 Agency may retain a procurement administrator to assist the
3 Agency in planning and carrying out the procurement events and
4 implementing the other requirements specified in such
5 subsection (c-5) of Section 1-75 of the Illinois Power Agency
6 Act, with the costs incurred by the Agency for the procurement
7 administrator to be recovered through fees charged to
8 applicants for selection to sell and deliver renewable energy
9 credits to electric utilities pursuant to subsection (c-5) of
10 Section 1-75 of the Illinois Power Agency Act. The procurement
11 process set forth in Section 1-75 of the Illinois Power Agency
12 Act and subsection (e) of this Section shall be administered
13 by a procurement administrator and monitored by a procurement
14 monitor.
15 (1) The procurement administrator shall:
16 (i) design the final procurement process in
17 accordance with Section 1-75 of the Illinois Power
18 Agency Act and subsection (e) of this Section
19 following Commission approval of the procurement plan;
20 (ii) develop benchmarks in accordance with
21 subsection (e)(3) to be used to evaluate bids; these
22 benchmarks shall be submitted to the Commission for
23 review and approval on a confidential basis prior to
24 the procurement event;
25 (iii) serve as the interface between the electric
26 utility and suppliers;
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1 (iv) manage the bidder pre-qualification and
2 registration process;
3 (v) obtain the electric utilities' agreement to
4 the final form of all supply contracts and credit
5 collateral agreements;
6 (vi) administer the request for proposals process;
7 (vii) have the discretion to negotiate to
8 determine whether bidders are willing to lower the
9 price of bids that meet the benchmarks approved by the
10 Commission; any post-bid negotiations with bidders
11 shall be limited to price only and shall be completed
12 within 24 hours after opening the sealed bids and
13 shall be conducted in a fair and unbiased manner; in
14 conducting the negotiations, there shall be no
15 disclosure of any information derived from proposals
16 submitted by competing bidders; if information is
17 disclosed to any bidder, it shall be provided to all
18 competing bidders;
19 (viii) maintain confidentiality of supplier and
20 bidding information in a manner consistent with all
21 applicable laws, rules, regulations, and tariffs;
22 (ix) submit a confidential report to the
23 Commission recommending acceptance or rejection of
24 bids;
25 (x) notify the utility of contract counterparties
26 and contract specifics; and
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1 (xi) administer related contingency procurement
2 events.
3 (2) The procurement monitor, who shall be retained by
4 the Commission, shall:
5 (i) monitor interactions among the procurement
6 administrator, suppliers, and utility;
7 (ii) monitor and report to the Commission on the
8 progress of the procurement process;
9 (iii) provide an independent confidential report
10 to the Commission regarding the results of the
11 procurement event;
12 (iv) assess compliance with the procurement plans
13 approved by the Commission for each utility that on
14 December 31, 2005 provided electric service to at
15 least 100,000 customers in Illinois and for each small
16 multi-jurisdictional utility that on December 31, 2005
17 served less than 100,000 customers in Illinois;
18 (v) preserve the confidentiality of supplier and
19 bidding information in a manner consistent with all
20 applicable laws, rules, regulations, and tariffs;
21 (vi) provide expert advice to the Commission and
22 consult with the procurement administrator regarding
23 issues related to procurement process design, rules,
24 protocols, and policy-related matters; and
25 (vii) consult with the procurement administrator
26 regarding the development and use of benchmark
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1 criteria, standard form contracts, credit policies,
2 and bid documents.
3 (d) Except as provided in subsection (j), the planning
4 process shall be conducted as follows:
5 (1) Beginning in 2008, each Illinois utility procuring
6 power pursuant to this Section shall annually provide a
7 range of load forecasts to the Illinois Power Agency by
8 July 15 of each year, or such other date as may be required
9 by the Commission or Agency. The load forecasts shall
10 cover the 5-year procurement planning period for the next
11 procurement plan and shall include hourly data
12 representing a high-load, low-load, and expected-load
13 scenario for the load of those retail customers included
14 in the plan's electric supply service requirements. The
15 utility shall provide supporting data and assumptions for
16 each of the scenarios.
17 (2) Beginning in 2008, the Illinois Power Agency shall
18 prepare a procurement plan by August 15th of each year, or
19 such other date as may be required by the Commission. The
20 procurement plan shall identify the portfolio of
21 demand-response and power and energy products to be
22 procured. Cost-effective demand-response measures shall be
23 procured as set forth in item (iii) of subsection (b) of
24 this Section. Copies of the procurement plan shall be
25 posted and made publicly available on the Agency's and
26 Commission's websites, and copies shall also be provided
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1 to each affected electric utility. An affected utility
2 shall have 30 days following the date of posting to
3 provide comment to the Agency on the procurement plan.
4 Other interested entities also may comment on the
5 procurement plan. All comments submitted to the Agency
6 shall be specific, supported by data or other detailed
7 analyses, and, if objecting to all or a portion of the
8 procurement plan, accompanied by specific alternative
9 wording or proposals. All comments shall be posted on the
10 Agency's and Commission's websites. During this 30-day
11 comment period, the Agency shall hold at least one public
12 hearing within each utility's service area for the purpose
13 of receiving public comment on the procurement plan.
14 Within 14 days following the end of the 30-day review
15 period, the Agency shall revise the procurement plan as
16 necessary based on the comments received and file the
17 procurement plan with the Commission and post the
18 procurement plan on the websites.
19 (3) Within 5 days after the filing of the procurement
20 plan, any person objecting to the procurement plan shall
21 file an objection with the Commission. Within 10 days
22 after the filing, the Commission shall determine whether a
23 hearing is necessary. The Commission shall enter its order
24 confirming or modifying the procurement plan within 90
25 days after the filing of the procurement plan by the
26 Illinois Power Agency.
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1 (4) The Commission shall approve the procurement plan,
2 including expressly the forecast used in the procurement
3 plan, if the Commission determines that it will ensure
4 adequate, reliable, affordable, efficient, and
5 environmentally sustainable electric service at the lowest
6 total cost over time, taking into account any benefits of
7 price stability.
8 (4.5) The Commission shall review the Agency's
9 recommendations for the selection of applicants to enter
10 into long-term contracts for the sale and delivery of
11 renewable energy credits from new renewable energy
12 facilities to be constructed at or adjacent to the sites
13 of coal-fueled electric generating facilities in this
14 State in accordance with the provisions of subsection
15 (c-5) of Section 1-75 of the Illinois Power Agency Act,
16 and shall approve the Agency's recommendations if the
17 Commission determines that the applicants recommended by
18 the Agency for selection, the proposed new renewable
19 energy facilities to be constructed, the amounts of
20 renewable energy credits to be delivered pursuant to the
21 contracts, and the other terms of the contracts, are
22 consistent with the requirements of subsection (c-5) of
23 Section 1-75 of the Illinois Power Agency Act.
24 (e) The procurement process shall include each of the
25 following components:
26 (1) Solicitation, pre-qualification, and registration
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1 of bidders. The procurement administrator shall
2 disseminate information to potential bidders to promote a
3 procurement event, notify potential bidders that the
4 procurement administrator may enter into a post-bid price
5 negotiation with bidders that meet the applicable
6 benchmarks, provide supply requirements, and otherwise
7 explain the competitive procurement process. In addition
8 to such other publication as the procurement administrator
9 determines is appropriate, this information shall be
10 posted on the Illinois Power Agency's and the Commission's
11 websites. The procurement administrator shall also
12 administer the prequalification process, including
13 evaluation of credit worthiness, compliance with
14 procurement rules, and agreement to the standard form
15 contract developed pursuant to paragraph (2) of this
16 subsection (e). The procurement administrator shall then
17 identify and register bidders to participate in the
18 procurement event.
19 (2) Standard contract forms and credit terms and
20 instruments. The procurement administrator, in
21 consultation with the utilities, the Commission, and other
22 interested parties and subject to Commission oversight,
23 shall develop and provide standard contract forms for the
24 supplier contracts that meet generally accepted industry
25 practices. Standard credit terms and instruments that meet
26 generally accepted industry practices shall be similarly
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1 developed. The procurement administrator shall make
2 available to the Commission all written comments it
3 receives on the contract forms, credit terms, or
4 instruments. If the procurement administrator cannot reach
5 agreement with the applicable electric utility as to the
6 contract terms and conditions, the procurement
7 administrator must notify the Commission of any disputed
8 terms and the Commission shall resolve the dispute. The
9 terms of the contracts shall not be subject to negotiation
10 by winning bidders, and the bidders must agree to the
11 terms of the contract in advance so that winning bids are
12 selected solely on the basis of price.
13 (3) Establishment of a market-based price benchmark.
14 As part of the development of the procurement process, the
15 procurement administrator, in consultation with the
16 Commission staff, Agency staff, and the procurement
17 monitor, shall establish benchmarks for evaluating the
18 final prices in the contracts for each of the products
19 that will be procured through the procurement process. The
20 benchmarks shall be based on price data for similar
21 products for the same delivery period and same delivery
22 hub, or other delivery hubs after adjusting for that
23 difference. The price benchmarks may also be adjusted to
24 take into account differences between the information
25 reflected in the underlying data sources and the specific
26 products and procurement process being used to procure
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1 power for the Illinois utilities. The benchmarks shall be
2 confidential but shall be provided to, and will be subject
3 to Commission review and approval, prior to a procurement
4 event.
5 (4) Request for proposals competitive procurement
6 process. The procurement administrator shall design and
7 issue a request for proposals to supply electricity in
8 accordance with each utility's procurement plan, as
9 approved by the Commission. The request for proposals
10 shall set forth a procedure for sealed, binding commitment
11 bidding with pay-as-bid settlement, and provision for
12 selection of bids on the basis of price.
13 (5) A plan for implementing contingencies in the event
14 of supplier default or failure of the procurement process
15 to fully meet the expected load requirement due to
16 insufficient supplier participation, Commission rejection
17 of results, or any other cause.
18 (i) Event of supplier default: In the event of
19 supplier default, the utility shall review the
20 contract of the defaulting supplier to determine if
21 the amount of supply is 200 megawatts or greater, and
22 if there are more than 60 days remaining of the
23 contract term. If both of these conditions are met,
24 and the default results in termination of the
25 contract, the utility shall immediately notify the
26 Illinois Power Agency that a request for proposals
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1 must be issued to procure replacement power, and the
2 procurement administrator shall run an additional
3 procurement event. If the contracted supply of the
4 defaulting supplier is less than 200 megawatts or
5 there are less than 60 days remaining of the contract
6 term, the utility shall procure power and energy from
7 the applicable regional transmission organization
8 market, including ancillary services, capacity, and
9 day-ahead or real time energy, or both, for the
10 duration of the contract term to replace the
11 contracted supply; provided, however, that if a needed
12 product is not available through the regional
13 transmission organization market it shall be purchased
14 from the wholesale market.
15 (ii) Failure of the procurement process to fully
16 meet the expected load requirement: If the procurement
17 process fails to fully meet the expected load
18 requirement due to insufficient supplier participation
19 or due to a Commission rejection of the procurement
20 results, the procurement administrator, the
21 procurement monitor, and the Commission staff shall
22 meet within 10 days to analyze potential causes of low
23 supplier interest or causes for the Commission
24 decision. If changes are identified that would likely
25 result in increased supplier participation, or that
26 would address concerns causing the Commission to
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1 reject the results of the prior procurement event, the
2 procurement administrator may implement those changes
3 and rerun the request for proposals process according
4 to a schedule determined by those parties and
5 consistent with Section 1-75 of the Illinois Power
6 Agency Act and this subsection. In any event, a new
7 request for proposals process shall be implemented by
8 the procurement administrator within 90 days after the
9 determination that the procurement process has failed
10 to fully meet the expected load requirement.
11 (iii) In all cases where there is insufficient
12 supply provided under contracts awarded through the
13 procurement process to fully meet the electric
14 utility's load requirement, the utility shall meet the
15 load requirement by procuring power and energy from
16 the applicable regional transmission organization
17 market, including ancillary services, capacity, and
18 day-ahead or real time energy, or both; provided,
19 however, that if a needed product is not available
20 through the regional transmission organization market
21 it shall be purchased from the wholesale market.
22 (6) The procurement processes described in this
23 subsection and in subsection (c-5) of Section 1-75 of the
24 Illinois Power Agency Act are exempt from the requirements
25 of the Illinois Procurement Code, pursuant to Section
26 20-10 of that Code.
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1 (f) Within 2 business days after opening the sealed bids,
2 the procurement administrator shall submit a confidential
3 report to the Commission. The report shall contain the results
4 of the bidding for each of the products along with the
5 procurement administrator's recommendation for the acceptance
6 and rejection of bids based on the price benchmark criteria
7 and other factors observed in the process. The procurement
8 monitor also shall submit a confidential report to the
9 Commission within 2 business days after opening the sealed
10 bids. The report shall contain the procurement monitor's
11 assessment of bidder behavior in the process as well as an
12 assessment of the procurement administrator's compliance with
13 the procurement process and rules. The Commission shall review
14 the confidential reports submitted by the procurement
15 administrator and procurement monitor, and shall accept or
16 reject the recommendations of the procurement administrator
17 within 2 business days after receipt of the reports.
18 (g) Within 3 business days after the Commission decision
19 approving the results of a procurement event, the utility
20 shall enter into binding contractual arrangements with the
21 winning suppliers using the standard form contracts; except
22 that the utility shall not be required either directly or
23 indirectly to execute the contracts if a tariff that is
24 consistent with subsection (l) of this Section has not been
25 approved and placed into effect for that utility.
26 (h) For the procurement of standard wholesale products,
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1 the names of the successful bidders and the load weighted
2 average of the winning bid prices for each contract type and
3 for each contract term shall be made available to the public at
4 the time of Commission approval of a procurement event. For
5 procurements conducted to meet the requirements of subsection
6 (b) of Section 1-56 or subsection (c) of Section 1-75 of the
7 Illinois Power Agency Act governed by the provisions of this
8 Section, the address and nameplate capacity of the new
9 renewable energy generating facility proposed by a winning
10 bidder shall also be made available to the public at the time
11 of Commission approval of a procurement event, along with the
12 business address and contact information for any winning
13 bidder. An estimate or approximation of the nameplate capacity
14 of the new renewable energy generating facility may be
15 disclosed if necessary to protect the confidentiality of
16 individual bid prices.
17 The Commission, the procurement monitor, the procurement
18 administrator, the Illinois Power Agency, and all participants
19 in the procurement process shall maintain the confidentiality
20 of all other supplier and bidding information in a manner
21 consistent with all applicable laws, rules, regulations, and
22 tariffs. Confidential information, including the confidential
23 reports submitted by the procurement administrator and
24 procurement monitor pursuant to subsection (f) of this
25 Section, shall not be made publicly available and shall not be
26 discoverable by any party in any proceeding, absent a
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1 compelling demonstration of need, nor shall those reports be
2 admissible in any proceeding other than one for law
3 enforcement purposes.
4 (i) Within 2 business days after a Commission decision
5 approving the results of a procurement event or such other
6 date as may be required by the Commission from time to time,
7 the utility shall file for informational purposes with the
8 Commission its actual or estimated retail supply charges, as
9 applicable, by customer supply group reflecting the costs
10 associated with the procurement and computed in accordance
11 with the tariffs filed pursuant to subsection (l) of this
12 Section and approved by the Commission.
13 (j) Within 60 days following August 28, 2007 (the
14 effective date of Public Act 95-481), each electric utility
15 that on December 31, 2005 provided electric service to at
16 least 100,000 customers in Illinois shall prepare and file
17 with the Commission an initial procurement plan, which shall
18 conform in all material respects to the requirements of the
19 procurement plan set forth in subsection (b); provided,
20 however, that the Illinois Power Agency Act shall not apply to
21 the initial procurement plan prepared pursuant to this
22 subsection. The initial procurement plan shall identify the
23 portfolio of power and energy products to be procured and
24 delivered for the period June 2008 through May 2009, and shall
25 identify the proposed procurement administrator, who shall
26 have the same experience and expertise as is required of a
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1 procurement administrator hired pursuant to Section 1-75 of
2 the Illinois Power Agency Act. Copies of the procurement plan
3 shall be posted and made publicly available on the
4 Commission's website. The initial procurement plan may include
5 contracts for renewable resources that extend beyond May 2009.
6 (i) Within 14 days following filing of the initial
7 procurement plan, any person may file a detailed objection
8 with the Commission contesting the procurement plan
9 submitted by the electric utility. All objections to the
10 electric utility's plan shall be specific, supported by
11 data or other detailed analyses. The electric utility may
12 file a response to any objections to its procurement plan
13 within 7 days after the date objections are due to be
14 filed. Within 7 days after the date the utility's response
15 is due, the Commission shall determine whether a hearing
16 is necessary. If it determines that a hearing is
17 necessary, it shall require the hearing to be completed
18 and issue an order on the procurement plan within 60 days
19 after the filing of the procurement plan by the electric
20 utility.
21 (ii) The order shall approve or modify the procurement
22 plan, approve an independent procurement administrator,
23 and approve or modify the electric utility's tariffs that
24 are proposed with the initial procurement plan. The
25 Commission shall approve the procurement plan if the
26 Commission determines that it will ensure adequate,
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1 reliable, affordable, efficient, and environmentally
2 sustainable electric service at the lowest total cost over
3 time, taking into account any benefits of price stability.
4 (k) (Blank).
5 (k-5) (Blank).
6 (l) An electric utility shall recover its costs incurred
7 under this Section and subsection (c-5) of Section 1-75 of the
8 Illinois Power Agency Act, including, but not limited to, the
9 costs of procuring power and energy demand-response resources
10 under this Section and its costs for purchasing renewable
11 energy credits pursuant to subsection (c-5) of Section 1-75 of
12 the Illinois Power Agency Act. The utility shall file with the
13 initial procurement plan its proposed tariffs through which
14 its costs of procuring power that are incurred pursuant to a
15 Commission-approved procurement plan and those other costs
16 identified in this subsection (l), will be recovered. The
17 tariffs shall include a formula rate or charge designed to
18 pass through both the costs incurred by the utility in
19 procuring a supply of electric power and energy for the
20 applicable customer classes with no mark-up or return on the
21 price paid by the utility for that supply, plus any just and
22 reasonable costs that the utility incurs in arranging and
23 providing for the supply of electric power and energy. The
24 formula rate or charge shall also contain provisions that
25 ensure that its application does not result in over or under
26 recovery due to changes in customer usage and demand patterns,
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1 and that provide for the correction, on at least an annual
2 basis, of any accounting errors that may occur. A utility
3 shall recover through the tariff all reasonable costs incurred
4 to implement or comply with any procurement plan that is
5 developed and put into effect pursuant to Section 1-75 of the
6 Illinois Power Agency Act and this Section, and for the
7 procurement of renewable energy credits pursuant to subsection
8 (c-5) of Section 1-75 of the Illinois Power Agency Act,
9 including any fees assessed by the Illinois Power Agency,
10 costs associated with load balancing, and contingency plan
11 costs. The electric utility shall also recover its full costs
12 of procuring electric supply for which it contracted before
13 the effective date of this Section in conjunction with the
14 provision of full requirements service under fixed-price
15 bundled service tariffs subsequent to December 31, 2006. All
16 such costs shall be deemed to have been prudently incurred.
17 The pass-through tariffs that are filed and approved pursuant
18 to this Section shall not be subject to review under, or in any
19 way limited by, Section 16-111(i) of this Act. All of the costs
20 incurred by the electric utility associated with the purchase
21 of zero emission credits in accordance with subsection (d-5)
22 of Section 1-75 of the Illinois Power Agency Act, all costs
23 incurred by the electric utility associated with the purchase
24 of carbon mitigation credits in accordance with subsection
25 (d-10) of Section 1-75 of the Illinois Power Agency Act, and,
26 beginning June 1, 2017, all of the costs incurred by the
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1 electric utility associated with the purchase of renewable
2 energy resources in accordance with Sections 1-56 and 1-75 of
3 the Illinois Power Agency Act, and all of the costs incurred by
4 the electric utility in purchasing renewable energy credits in
5 accordance with subsection (c-5) of Section 1-75 of the
6 Illinois Power Agency Act, shall be recovered through the
7 electric utility's tariffed charges applicable to all of its
8 retail customers, as specified in subsection (k) or subsection
9 (i-5), as applicable, of Section 16-108 of this Act, and shall
10 not be recovered through the electric utility's tariffed
11 charges for electric power and energy supply to its eligible
12 retail customers.
13 (m) The Commission has the authority to adopt rules to
14 carry out the provisions of this Section. For the public
15 interest, safety, and welfare, the Commission also has
16 authority to adopt rules to carry out the provisions of this
17 Section on an emergency basis immediately following August 28,
18 2007 (the effective date of Public Act 95-481).
19 (n) Notwithstanding any other provision of this Act, any
20 affiliated electric utilities that submit a single procurement
21 plan covering their combined needs may procure for those
22 combined needs in conjunction with that plan, and may enter
23 jointly into power supply contracts, purchases, and other
24 procurement arrangements, and allocate capacity and energy and
25 cost responsibility therefor among themselves in proportion to
26 their requirements.
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1 (o) On or before June 1 of each year, the Commission shall
2 hold an informal hearing for the purpose of receiving comments
3 on the prior year's procurement process and any
4 recommendations for change.
5 (p) An electric utility subject to this Section may
6 propose to invest, lease, own, or operate an electric
7 generation facility as part of its procurement plan, provided
8 the utility demonstrates that such facility is the least-cost
9 option to provide electric service to those retail customers
10 included in the plan's electric supply service requirements.
11 If the facility is shown to be the least-cost option and is
12 included in a procurement plan prepared in accordance with
13 Section 1-75 of the Illinois Power Agency Act and this
14 Section, then the electric utility shall make a filing
15 pursuant to Section 8-406 of this Act, and may request of the
16 Commission any statutory relief required thereunder. If the
17 Commission grants all of the necessary approvals for the
18 proposed facility, such supply shall thereafter be considered
19 as a pre-existing contract under subsection (b) of this
20 Section. The Commission shall in any order approving a
21 proposal under this subsection specify how the utility will
22 recover the prudently incurred costs of investing in, leasing,
23 owning, or operating such generation facility through just and
24 reasonable rates charged to those retail customers included in
25 the plan's electric supply service requirements. Cost recovery
26 for facilities included in the utility's procurement plan
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1 pursuant to this subsection shall not be subject to review
2 under or in any way limited by the provisions of Section
3 16-111(i) of this Act. Nothing in this Section is intended to
4 prohibit a utility from filing for a fuel adjustment clause as
5 is otherwise permitted under Section 9-220 of this Act.
6 (q) If the Illinois Power Agency filed with the
7 Commission, under Section 16-111.5 of this Act, its proposed
8 procurement plan for the period commencing June 1, 2017, and
9 the Commission has not yet entered its final order approving
10 the plan on or before the effective date of this amendatory Act
11 of the 99th General Assembly, then the Illinois Power Agency
12 shall file a notice of withdrawal with the Commission, after
13 the effective date of this amendatory Act of the 99th General
14 Assembly, to withdraw the proposed procurement of renewable
15 energy resources to be approved under the plan, other than the
16 procurement of renewable energy credits from distributed
17 renewable energy generation devices using funds previously
18 collected from electric utilities' retail customers that take
19 service pursuant to electric utilities' hourly pricing tariff
20 or tariffs and, for an electric utility that serves less than
21 100,000 retail customers in the State, other than the
22 procurement of renewable energy credits from distributed
23 renewable energy generation devices. Upon receipt of the
24 notice, the Commission shall enter an order that approves the
25 withdrawal of the proposed procurement of renewable energy
26 resources from the plan. The initially proposed procurement of
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1 renewable energy resources shall not be approved or be the
2 subject of any further hearing, investigation, proceeding, or
3 order of any kind.
4 This amendatory Act of the 99th General Assembly preempts
5 and supersedes any order entered by the Commission that
6 approved the Illinois Power Agency's procurement plan for the
7 period commencing June 1, 2017, to the extent it is
8 inconsistent with the provisions of this amendatory Act of the
9 99th General Assembly. To the extent any previously entered
10 order approved the procurement of renewable energy resources,
11 the portion of that order approving the procurement shall be
12 void, other than the procurement of renewable energy credits
13 from distributed renewable energy generation devices using
14 funds previously collected from electric utilities' retail
15 customers that take service under electric utilities' hourly
16 pricing tariff or tariffs and, for an electric utility that
17 serves less than 100,000 retail customers in the State, other
18 than the procurement of renewable energy credits for
19 distributed renewable energy generation devices.
20 (Source: P.A. 102-662, eff. 9-15-21.)
21 (220 ILCS 5/16-115A)
22 Sec. 16-115A. Obligations of alternative retail electric
23 suppliers.
24 (a) An alternative retail electric supplier:
25 (i) shall comply with the requirements imposed on
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1 public utilities by Sections 8-201 through 8-207, 8-301,
2 8-505 and 8-507 of this Act, to the extent that these
3 Sections have application to the services being offered by
4 the alternative retail electric supplier;
5 (ii) shall continue to comply with the requirements
6 for certification stated in subsection (d) of Section
7 16-115;
8 (iii) by May 31, 2020 and every June 30 thereafter,
9 shall submit to the Commission and the Office of the
10 Attorney General the rates the retail electric supplier
11 charged to residential customers in the prior year,
12 including each distinct rate charged and whether the rate
13 was a fixed or variable rate, the basis for the variable
14 rate, and any fees charged in addition to the supply rate,
15 including monthly fees, flat fees, or other service
16 charges; and
17 (iv) shall make publicly available on its website,
18 without the need for a customer login, rate information
19 for all of its variable, time-of-use, and fixed rate
20 contracts currently available to residential customers,
21 including, but not limited to, fixed monthly charges,
22 early termination fees, and kilowatt-hour charges; and
23 (v) shall retire all renewable energy credits, as
24 defined in Section 1-10 of the Illinois Power Agency Act,
25 and any other environmental attributes of the energy
26 supply procured from renewable energy resources in
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1 compliance with subsection (h) of this Section.
2 (b) An alternative retail electric supplier shall obtain
3 verifiable authorization from a customer, in a form or manner
4 approved by the Commission consistent with Section 2EE of the
5 Consumer Fraud and Deceptive Business Practices Act, before
6 the customer is switched from another supplier.
7 (c) No alternative retail electric supplier, or electric
8 utility other than the electric utility in whose service area
9 a customer is located, shall (i) enter into or employ any
10 arrangements which have the effect of preventing a retail
11 customer with a maximum electrical demand of less than one
12 megawatt from having access to the services of the electric
13 utility in whose service area the customer is located or (ii)
14 charge retail customers for such access. This subsection shall
15 not be construed to prevent an arms-length agreement between a
16 supplier and a retail customer that sets a term of service,
17 notice period for terminating service and provisions governing
18 early termination through a tariff or contract as allowed by
19 Section 16-119.
20 (d) An alternative retail electric supplier that is
21 certified to serve residential or small commercial retail
22 customers shall not:
23 (1) deny service to a customer or group of customers
24 nor establish any differences as to prices, terms,
25 conditions, services, products, facilities, or in any
26 other respect, whereby such denial or differences are
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1 based upon race, gender or income, except as provided in
2 Section 16-115E.
3 (2) deny service to a customer or group of customers
4 based on locality nor establish any unreasonable
5 difference as to prices, terms, conditions, services,
6 products, or facilities as between localities.
7 (3) warrant that it has a residential customer or
8 small commercial retail customer's express consent
9 agreement to access interval data as described in
10 subsection (b) of Section 16-122, unless the alternative
11 retail electric supplier has:
12 (A) disclosed to the consumer at the outset of the
13 offer that the alternative retail electric supplier
14 will access the consumer's interval data from the
15 consumer's utility with the consumer's express
16 agreement and the consumer's option to refuse to
17 provide express agreement to access the consumer's
18 interval data; and
19 (B) obtained the consumer's express agreement for
20 the alternative retail electric supplier to access the
21 consumer's interval data from the consumer's utility
22 in a separate letter of agency, a distinct response to
23 a third-party verification, or as a separate
24 affirmative consent during a recorded enrollment
25 initiated by the consumer. The disclosure by the
26 alternative retail electric supplier to the consumer
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1 in this Section shall be conducted in, translated
2 into, and provided in a language in which the consumer
3 subject to the disclosure is able to understand and
4 communicate.
5 (4) release, sell, license, or otherwise disclose any
6 customer interval data obtained under Section 16-122 to
7 any third person except as provided for in Section 16-122
8 and paragraphs (1) through (4) of subsection (d-5) of
9 Section 2EE of the Consumer Fraud and Deceptive Business
10 Practices Act.
11 (e) An alternative retail electric supplier shall comply
12 with the following requirements with respect to the marketing,
13 offering and provision of products or services to residential
14 and small commercial retail customers:
15 (i) All marketing materials, including, but not
16 limited to, electronic marketing materials, in-person
17 solicitations, and telephone solicitations, shall contain
18 information that adequately discloses the prices, terms,
19 and conditions of the products or services that the
20 alternative retail electric supplier is offering or
21 selling to the customer and shall disclose the current
22 utility electric supply price to compare applicable at the
23 time the alternative retail electric supplier is offering
24 or selling the products or services to the customer and
25 shall disclose the date on which the utility electric
26 supply price to compare became effective and the date on
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1 which it will expire. The utility electric supply price to
2 compare shall be the sum of the electric supply charge and
3 the transmission services charge and shall not include the
4 purchased electricity adjustment. The disclosure shall
5 include a statement that the price to compare does not
6 include the purchased electricity adjustment, and, if
7 applicable, the range of the purchased electricity
8 adjustment. All marketing materials, including, but not
9 limited to, electronic marketing materials, in-person
10 solicitations, and telephone solicitations, shall include
11 the following statement:
12 "(Name of the alternative retail electric
13 supplier) is not the same entity as your electric
14 delivery company. You are not required to enroll with
15 (name of alternative retail electric supplier).
16 Beginning on (effective date), the electric supply
17 price to compare is (price in cents per kilowatt
18 hour). The electric utility electric supply price will
19 expire on (expiration date). The utility electric
20 supply price to compare does not include the purchased
21 electricity adjustment factor. For more information go
22 to the Illinois Commerce Commission's free website at
23 www.pluginillinois.org.".
24 If applicable, the statement shall also include the
25 following statement:
26 "The purchased electricity adjustment factor may
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1 range between +.5 cents and -.5 cents per kilowatt
2 hour.".
3 This paragraph (i) does not apply to goodwill or
4 institutional advertising.
5 (ii) Before any customer is switched from another
6 supplier, the alternative retail electric supplier shall
7 give the customer written information that adequately
8 discloses, in plain language, the prices, terms and
9 conditions of the products and services being offered and
10 sold to the customer. This written information shall be
11 provided in a language in which the customer subject to
12 the marketing or solicitation is able to understand and
13 communicate, and the alternative retail electric supplier
14 shall not switch a customer who is unable to understand
15 and communicate in a language in which the marketing or
16 solicitation was conducted. The alternative retail
17 electric supplier shall comply with Section 2N of the
18 Consumer Fraud and Deceptive Business Practices Act.
19 (iii) An alternative retail electric supplier shall
20 provide documentation to the Commission and to customers
21 that substantiates any claims made by the alternative
22 retail electric supplier regarding the technologies and
23 fuel types used to generate the electricity offered or
24 sold to customers.
25 (iv) The alternative retail electric supplier shall
26 provide to the customer (1) itemized billing statements
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1 that describe the products and services provided to the
2 customer and their prices, and (2) an additional
3 statement, at least annually, that adequately discloses
4 the average monthly prices, and the terms and conditions,
5 of the products and services sold to the customer.
6 (v) All in-person and telephone solicitations shall be
7 conducted in, translated into, and provided in a language
8 in which the consumer subject to the marketing or
9 solicitation is able to understand and communicate. An
10 alternative retail electric supplier shall terminate a
11 solicitation if the consumer subject to the marketing or
12 communication is unable to understand and communicate in
13 the language in which the marketing or solicitation is
14 being conducted. An alternative retail electric supplier
15 shall comply with Section 2N of the Consumer Fraud and
16 Deceptive Business Practices Act.
17 (vi) Each alternative retail electric supplier shall
18 conduct training for individual representatives engaged in
19 in-person solicitation and telemarketing to residential
20 customers on behalf of that alternative retail electric
21 supplier prior to conducting any such solicitations on the
22 alternative retail electric supplier's behalf. Each
23 alternative retail electric supplier shall submit a copy
24 of its training material to the Commission on an annual
25 basis and the Commission shall have the right to review
26 and require updates to the material. After initial
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1 training, each alternative retail electric supplier shall
2 be required to conduct refresher training for its
3 individual representatives every 6 months.
4 (f) An alternative retail electric supplier may limit the
5 overall size or availability of a service offering by
6 specifying one or more of the following: a maximum number of
7 customers, maximum amount of electric load to be served, time
8 period during which the offering will be available, or other
9 comparable limitation, but not including the geographic
10 locations of customers within the area which the alternative
11 retail electric supplier is certificated to serve. The
12 alternative retail electric supplier shall file the terms and
13 conditions of such service offering including the applicable
14 limitations with the Commission prior to making the service
15 offering available to customers.
16 (g) Nothing in this Section shall be construed as
17 preventing an alternative retail electric supplier, which is
18 an affiliate of, or which contracts with, (i) an industry or
19 trade organization or association, (ii) a membership
20 organization or association that exists for a purpose other
21 than the purchase of electricity, or (iii) another
22 organization that meets criteria established in a rule adopted
23 by the Commission, from offering through the organization or
24 association services at prices, terms and conditions that are
25 available solely to the members of the organization or
26 association.
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1 (h) For all potentially eligible retail customers, as
2 defined in Section 16-111.5, served by an alternative retail
3 electric supplier, or electric utility other than the electric
4 utility in whose service area a customer is located, such
5 supplier or utility shall purchase products that include the
6 same percentage of renewable energy resources, as defined in
7 Section 1-10 of the Illinois Power Agency Act, as was procured
8 for the utility in whose service area such customers are
9 located for the immediately prior delivery year. Such clean
10 energy shall include all environmental attributes as described
11 in Section 16-111.5 and match the eligibility criteria of
12 resources eligible for the renewable portfolio standard
13 described in subsections (c)(I) and (c)(J) of Section 1-75 of
14 the Illinois Power Agency Act.
15 (Source: P.A. 102-459, eff. 8-20-21; 103-237, eff. 6-30-23.)
16 (220 ILCS 5/16-115D)
17 Sec. 16-115D. Renewable portfolio standard for alternative
18 retail electric suppliers and electric utilities operating
19 outside their service territories.
20 (a) An alternative retail electric supplier shall be
21 responsible for procuring cost-effective renewable energy
22 resources as required under item (5) of subsection (d) of
23 Section 16-115 of this Act as outlined herein:
24 (1) The definition of renewable energy resources
25 contained in Section 1-10 of the Illinois Power Agency Act
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1 applies to all renewable energy resources required to be
2 procured by alternative retail electric suppliers.
3 (2) Through May 31, 2017, the quantity of renewable
4 energy resources shall be measured as a percentage of the
5 actual amount of metered electricity (megawatt-hours)
6 delivered by the alternative retail electric supplier to
7 Illinois retail customers during the 12-month period June
8 1 through May 31, commencing June 1, 2009, and the
9 comparable 12-month period in each year thereafter except
10 as provided in item (6) of this subsection (a).
11 (3) Through May 31, 2017, the quantity of renewable
12 energy resources shall be in amounts at least equal to the
13 annual percentages set forth in item (1) of subsection (c)
14 of Section 1-75 of the Illinois Power Agency Act. At least
15 60% of the renewable energy resources procured pursuant to
16 items (1) and (3) of subsection (b) of this Section shall
17 come from wind generation and, starting June 1, 2015, at
18 least 6% of the renewable energy resources procured
19 pursuant to items (1) and (3) of subsection (b) of this
20 Section shall come from solar photovoltaics. If, in any
21 given year, an alternative retail electric supplier does
22 not purchase at least these levels of renewable energy
23 resources, then the alternative retail electric supplier
24 shall make alternative compliance payments, as described
25 in subsection (d) of this Section.
26 (3.5) For the delivery year commencing June 1, 2017,
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1 the quantity of renewable energy resources shall be at
2 least 13.0% of the uncovered amount of metered electricity
3 (megawatt-hours) delivered by the alternative retail
4 electric supplier to Illinois retail customers during the
5 delivery year, which uncovered amount shall equal 50% of
6 such metered electricity delivered by the alternative
7 retail electric supplier. For the delivery year commencing
8 June 1, 2018, the quantity of renewable energy resources
9 shall be at least 14.5% of the uncovered amount of metered
10 electricity (megawatt-hours) delivered by the alternative
11 retail electric supplier to Illinois retail customers
12 during the delivery year, which uncovered amount shall
13 equal 25% of such metered electricity delivered by the
14 alternative retail electric supplier. At least 32% of the
15 renewable energy resources procured by the alternative
16 retail electric supplier for its uncovered portion under
17 this paragraph (3.5) shall come from wind or photovoltaic
18 generation. The renewable energy resources procured under
19 this paragraph (3.5) shall not include any resources from
20 a facility whose costs were being recovered through rates
21 regulated by any state or states on or after January 1,
22 2017.
23 (4) The quantity and source of renewable energy
24 resources shall be independently verified through the PJM
25 Environmental Information System Generation Attribute
26 Tracking System (PJM-GATS) or the Midwest Renewable Energy
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1 Tracking System (M-RETS), which shall document the
2 location of generation, resource type, month, and year of
3 generation for all qualifying renewable energy resources
4 that an alternative retail electric supplier uses to
5 comply with this Section. No later than June 1, 2009, the
6 Illinois Power Agency shall provide PJM-GATS, M-RETS, and
7 alternative retail electric suppliers with all information
8 necessary to identify resources located in Illinois,
9 within states that adjoin Illinois or within portions of
10 the PJM and MISO footprint in the United States that
11 qualify under the definition of renewable energy resources
12 in Section 1-10 of the Illinois Power Agency Act for
13 compliance with this Section 16-115D. Alternative retail
14 electric suppliers shall not be subject to the
15 requirements in item (3) of subsection (c) of Section 1-75
16 of the Illinois Power Agency Act.
17 (5) All renewable energy credits used to comply with
18 this Section shall be permanently retired.
19 (6) The required procurement of renewable energy
20 resources by an alternative retail electric supplier shall
21 apply to all metered electricity delivered to Illinois
22 retail customers by the alternative retail electric
23 supplier pursuant to contracts executed or extended after
24 March 15, 2009.
25 (b) Compliance obligations.
26 (1) Through May 31, 2017, an alternative retail
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1 electric supplier shall comply with the renewable energy
2 portfolio standards by making an alternative compliance
3 payment, as described in subsection (d) of this Section,
4 to cover at least one-half of the alternative retail
5 electric supplier's compliance obligation for the period
6 prior to June 1, 2017.
7 (2) For the delivery years beginning June 1, 2017 and
8 June 1, 2018, an alternative retail electric supplier need
9 not make any alternative compliance payment to meet any
10 portion of its compliance obligation, as set forth in
11 paragraph (3.5) of subsection (a) of this Section.
12 (3) An alternative retail electric supplier shall use
13 any one or combination of the following means to cover the
14 remainder of the alternative retail electric supplier's
15 compliance obligation, as set forth in paragraphs (3) and
16 (3.5) of subsection (a) of this Section, not covered by an
17 alternative compliance payment made under paragraphs (1)
18 and (2) of this subsection (b) of this Section:
19 (A) Generating electricity using renewable energy
20 resources identified pursuant to item (4) of
21 subsection (a) of this Section.
22 (B) Purchasing electricity generated using
23 renewable energy resources identified pursuant to item
24 (4) of subsection (a) of this Section through an
25 energy contract.
26 (C) Purchasing renewable energy credits from
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1 renewable energy resources identified pursuant to item
2 (4) of subsection (a) of this Section.
3 (D) Making an alternative compliance payment as
4 described in subsection (d) of this Section.
5 (c) Use of renewable energy credits.
6 (1) Renewable energy credits that are not used by an
7 alternative retail electric supplier to comply with a
8 renewable portfolio standard in a compliance year may be
9 banked and carried forward up to 2 12-month compliance
10 periods after the compliance period in which the credit
11 was generated for the purpose of complying with a
12 renewable portfolio standard in those 2 subsequent
13 compliance periods. For the 2009-2010 and 2010-2011
14 compliance periods, an alternative retail electric
15 supplier may use renewable credits generated after
16 December 31, 2008 and before June 1, 2009 to comply with
17 this Section.
18 (2) An alternative retail electric supplier is
19 responsible for demonstrating that a renewable energy
20 credit used to comply with a renewable portfolio standard
21 is derived from a renewable energy resource and that the
22 alternative retail electric supplier has not used, traded,
23 sold, or otherwise transferred the credit.
24 (3) The same renewable energy credit may be used by an
25 alternative retail electric supplier to comply with a
26 federal renewable portfolio standard and a renewable
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1 portfolio standard established under this Act. An
2 alternative retail electric supplier that uses a renewable
3 energy credit to comply with a renewable portfolio
4 standard imposed by any other state may not use the same
5 credit to comply with a renewable portfolio standard
6 established under this Act.
7 (d) Alternative compliance payments.
8 (1) The Commission shall establish and post on its
9 website, within 5 business days after entering an order
10 approving a procurement plan pursuant to Section 1-75 of
11 the Illinois Power Agency Act, maximum alternative
12 compliance payment rates, expressed on a per kilowatt-hour
13 basis, that will be applicable in the first compliance
14 period following the plan approval. A separate maximum
15 alternative compliance payment rate shall be established
16 for the service territory of each electric utility that is
17 subject to subsection (c) of Section 1-75 of the Illinois
18 Power Agency Act. Each maximum alternative compliance
19 payment rate shall be equal to the maximum allowable
20 annual estimated average net increase due to the costs of
21 the utility's purchase of renewable energy resources
22 included in the amounts paid by eligible retail customers
23 in connection with electric service, as described in item
24 (2) of subsection (c) of Section 1-75 of the Illinois
25 Power Agency Act for the compliance period, and as
26 established in the approved procurement plan. Following
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1 each procurement event through which renewable energy
2 resources are purchased for one or more of these utilities
3 for the compliance period, the Commission shall establish
4 and post on its website estimates of the alternative
5 compliance payment rates, expressed on a per kilowatt-hour
6 basis, that shall apply for that compliance period.
7 Posting of the estimates shall occur no later than 10
8 business days following the procurement event, however,
9 the Commission shall not be required to establish and post
10 such estimates more often than once per calendar month. By
11 July 1 of each year, the Commission shall establish and
12 post on its website the actual alternative compliance
13 payment rates for the preceding compliance year. For
14 compliance years beginning prior to June 1, 2014, each
15 alternative compliance payment rate shall be equal to the
16 total amount of dollars that the utility contracted to
17 spend on renewable resources, excepting the additional
18 incremental cost attributable to solar resources, for the
19 compliance period divided by the forecasted load of
20 eligible retail customers, at the customers' meters, as
21 previously established in the Commission-approved
22 procurement plan for that compliance year. For compliance
23 years commencing on or after June 1, 2014, each
24 alternative compliance payment rate shall be equal to the
25 total amount of dollars that the utility contracted to
26 spend on all renewable resources for the compliance period
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1 divided by the forecasted load of retail customers for
2 which the utility is procuring renewable energy resources
3 in a given delivery year, at the customers' meters, as
4 previously established in the Commission-approved
5 procurement plan for that compliance year. The actual
6 alternative compliance payment rates may not exceed the
7 maximum alternative compliance payment rates established
8 for the compliance period. For purposes of this subsection
9 (d), the term "eligible retail customers" has the same
10 meaning as found in Section 16-111.5 of this Act.
11 (2) In any given compliance year, an alternative
12 retail electric supplier may elect to use alternative
13 compliance payments to comply with all or a part of the
14 applicable renewable portfolio standard. In the event that
15 an alternative retail electric supplier elects to make
16 alternative compliance payments to comply with all or a
17 part of the applicable renewable portfolio standard, such
18 payments shall be made by September 1, 2010 for the period
19 of June 1, 2009 to May 1, 2010 and by September 1 of each
20 year thereafter for the subsequent compliance period, in
21 the manner and form as determined by the Commission. Any
22 election by an alternative retail electric supplier to use
23 alternative compliance payments is subject to review by
24 the Commission under subsection (e) of this Section.
25 (3) An alternative retail electric supplier's
26 alternative compliance payments shall be computed
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1 separately for each electric utility's service territory
2 within which the alternative retail electric supplier
3 provided retail service during the compliance period,
4 provided that the electric utility was subject to
5 subsection (c) of Section 1-75 of the Illinois Power
6 Agency Act. For each service territory, the alternative
7 retail electric supplier's alternative compliance payment
8 shall be equal to (i) the actual alternative compliance
9 payment rate established in item (1) of this subsection
10 (d), multiplied by (ii) the actual amount of metered
11 electricity delivered by the alternative retail electric
12 supplier to retail customers for which the supplier has a
13 compliance obligation within the service territory during
14 the compliance period, multiplied by (iii) the result of
15 one minus the ratios of the quantity of renewable energy
16 resources used by the alternative retail electric supplier
17 to comply with the requirements of this Section within the
18 service territory to the product of the percentage of
19 renewable energy resources required under item (3) or
20 (3.5) of subsection (a) of this Section and the actual
21 amount of metered electricity delivered by the alternative
22 retail electrical supplier to retail customers for which
23 the supplier has a compliance obligation within the
24 service territory during the compliance period.
25 (4) Through May 31, 2017, all alternative compliance
26 payments by alternative retail electric suppliers shall be
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1 deposited in the Illinois Power Agency Renewable Energy
2 Resources Fund and used to purchase renewable energy
3 credits, in accordance with Section 1-56 of the Illinois
4 Power Agency Act. Beginning April 1, 2012 and by April 1 of
5 each year thereafter, the Illinois Power Agency shall
6 submit an annual report to the General Assembly, the
7 Commission, and alternative retail electric suppliers that
8 shall include, but not be limited to:
9 (A) the total amount of alternative compliance
10 payments received in aggregate from alternative retail
11 electric suppliers by planning year for all previous
12 planning years in which the alternative compliance
13 payment was in effect;
14 (B) the amount of those payments utilized to
15 purchased renewable energy credits itemized by the
16 date of each procurement in which the payments were
17 utilized; and
18 (C) the unused and remaining balance in the Agency
19 Renewable Energy Resources Fund attributable to those
20 payments.
21 (4.5) Beginning with the delivery year commencing June
22 1, 2017, all alternative compliance payments by
23 alternative retail electric suppliers shall be remitted to
24 the applicable electric utility. To facilitate this
25 remittance, each electric utility shall file a tariff with
26 the Commission no later than 30 days following the
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1 effective date of this amendatory Act of the 99th General
2 Assembly, which the Commission shall approve, after notice
3 and hearing, no later than 45 days after its filing. The
4 Illinois Power Agency shall use such payments to increase
5 the amount of renewable energy resources otherwise to be
6 procured under subsection (c) of Section 1-75 of the
7 Illinois Power Agency Act.
8 (5) The Commission, in consultation with the Illinois
9 Power Agency, shall establish a process or proceeding to
10 consider the impact of a federal renewable portfolio
11 standard, if enacted, on the operation of the alternative
12 compliance mechanism, which shall include, but not be
13 limited to, developing, to the extent permitted by the
14 applicable federal statute, an appropriate methodology to
15 apportion renewable energy credits retired as a result of
16 alternative compliance payments made in accordance with
17 this Section. The Commission shall commence any such
18 process or proceeding within 35 days after enactment of a
19 federal renewable portfolio standard.
20 (e) Each alternative retail electric supplier shall, by
21 September 1, 2010 and by September 1 of each year thereafter,
22 prepare and submit to the Commission a report, in a format to
23 be specified by the Commission, that provides information
24 certifying compliance by the alternative retail electric
25 supplier with this Section, including copies of all PJM-GATS
26 and M-RETS reports, and documentation relating to banking,
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1 retiring renewable energy credits, and any other information
2 that the Commission determines necessary to ensure compliance
3 with this Section.
4 An alternative retail electric supplier may file
5 commercially or financially sensitive information or trade
6 secrets with the Commission as provided under the rules of the
7 Commission. To be filed confidentially, the information shall
8 be accompanied by an affidavit that sets forth both the
9 reasons for the confidentiality and a public synopsis of the
10 information.
11 (f) The Commission may initiate a contested case to review
12 allegations that the alternative retail electric supplier has
13 violated this Section, including an order issued or rule
14 promulgated under this Section. In any such proceeding, the
15 alternative retail electric supplier shall have the burden of
16 proof. If the Commission finds, after notice and hearing, that
17 an alternative retail electric supplier has violated this
18 Section, then the Commission shall issue an order requiring
19 the alternative retail electric supplier to:
20 (1) immediately comply with this Section; and
21 (2) if the violation involves a failure to procure the
22 requisite quantity of renewable energy resources or pay
23 the applicable alternative compliance payment by the
24 annual deadline, the Commission shall require the
25 alternative retail electric supplier to double the
26 applicable alternative compliance payment that would
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1 otherwise be required to bring the alternative retail
2 electric supplier into compliance with this Section.
3 If an alternative retail electric supplier fails to comply
4 with the renewable energy resource portfolio requirement or
5 capacity portfolio requirement in this Section more than once
6 in a 5-year period, then the Commission shall revoke the
7 alternative electric supplier's certificate of service
8 authority. The Commission shall not accept an application for
9 a certificate of service authority from an alternative retail
10 electric supplier that has lost certification under this
11 subsection (f), or any corporate affiliate thereof, for at
12 least one year after the date of revocation.
13 (g) All of the provisions of this Section apply to
14 electric utilities operating outside their service area except
15 under item (2) of subsection (a) of this Section the quantity
16 of renewable energy resources shall be measured as a
17 percentage of the actual amount of electricity
18 (megawatt-hours) supplied in the State outside of the
19 utility's service territory during the 12-month period June 1
20 through May 31, commencing June 1, 2009, and the comparable
21 12-month period in each year thereafter except as provided in
22 item (6) of subsection (a) of this Section.
23 If any such utility fails to procure the requisite
24 quantity of renewable energy resources by the annual deadline,
25 then the Commission shall require the utility to double the
26 alternative compliance payment that would otherwise be
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1 required to bring the utility into compliance with this
2 Section.
3 If any such utility fails to comply with the renewable
4 energy resource portfolio requirement in this Section more
5 than once in a 5-year period, then the Commission shall order
6 the utility to cease all sales outside of the utility's
7 service territory for a period of at least one year.
8 (h) The provisions of this Section and the provisions of
9 subsection (d) of Section 16-115 of this Act relating to
10 procurement of renewable energy resources shall not apply to
11 an alternative retail electric supplier that operates a
12 combined heat and power system in this State or that has a
13 corporate affiliate that operates such a combined heat and
14 power system in this State that supplies electricity primarily
15 to or for the benefit of: (i) facilities owned by the supplier,
16 its subsidiary, or other corporate affiliate; (ii) facilities
17 electrically integrated with the electrical system of
18 facilities owned by the supplier, its subsidiary, or other
19 corporate affiliate; or (iii) facilities that are adjacent to
20 the site on which the combined heat and power system is
21 located.
22 (i) The obligations of alternative retail electric
23 suppliers and electric utilities operating outside their
24 service territories to procure renewable energy resources,
25 make alternative compliance payments, and file annual reports,
26 and the obligations of the Commission to determine and post
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1 alternative compliance payment rates, shall terminate after
2 May 31, 2019, provided that alternative retail electric
3 suppliers and electric utilities operating outside their
4 service territories shall be obligated to make all alternative
5 compliance payments that they were obligated to pay for
6 periods through and including May 31, 2019, but were not paid
7 as of that date. The Commission shall continue to enforce the
8 payment of unpaid alternative compliance payments in
9 accordance with subsections (f) and (g) of this Section. All
10 alternative compliance payments made after May 31, 2016 shall
11 be remitted to the applicable electric utility and used to
12 purchase renewable energy credits, in accordance with Section
13 1-75 of the Illinois Power Agency Act.
14 This subsection (i) is intended to accommodate the
15 transition to the procurement of renewable energy resources
16 for all retail customers in the amounts specified under
17 subsection (c) of Section 1-75 of the Illinois Power Agency
18 Act and Section 16-111.5 of this Act, including but not
19 limited to the transition to a single charge applicable to all
20 retail customers to recover the costs of these resources. Each
21 alternative retail electric supplier shall certify in its
22 annual reports filed pursuant to subsection (e) of this
23 Section after May 31, 2019, that its retail customers are not
24 paying the costs of alternative compliance payments or
25 renewable energy resources that the alternative retail
26 electric supplier is not required to remit or purchase under
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1 this Section. The Commission shall have the authority to
2 initiate an emergency rulemaking to adopt rules regarding such
3 certification.
4 (Source: P.A. 99-906, eff. 6-1-17.)
5 (220 ILCS 5/17-500)
6 Sec. 17-500. Jurisdiction. Except as provided in the
7 Electric Supplier Act, the Illinois Municipal Code, the
8 Municipal and Cooperative Electric Utility Planning and
9 Transparency Act, and this Article XVII, the Commission, or
10 any other agency or subdivision thereof of the State of
11 Illinois or any private entity shall have no jurisdiction over
12 any electric cooperative or municipal system regardless of
13 whether any election or elections as provided for herein have
14 been made, and all control regarding an electric cooperative
15 or municipal system shall be vested in the electric
16 cooperative's board of directors or trustees or the applicable
17 governing body of the municipal system.
18 (Source: P.A. 90-561, eff. 12-16-97.)
19 Section 110
. The Eminent Domain Act is amended by changing
20 Section 5-5-5 as follows:
21 (735 ILCS 30/5-5-5)
22 Sec. 5-5-5. Exercise of the power of eminent domain;
23 public use; blight.
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1 (a) In addition to all other limitations and requirements,
2 a condemning authority may not take or damage property by the
3 exercise of the power of eminent domain unless it is for a
4 public use, as set forth in this Section.
5 (a-5) Subsections (b), (c), (d), (e), and (f) of this
6 Section do not apply to the acquisition of property under the
7 O'Hare Modernization Act. A condemning authority may exercise
8 the power of eminent domain for the acquisition or damaging of
9 property under the O'Hare Modernization Act as provided for by
10 law in effect prior to the effective date of this Act.
11 (a-10) Subsections (b), (c), (d), (e), and (f) of this
12 Section do not apply to the acquisition or damaging of
13 property in furtherance of the goals and objectives of an
14 existing tax increment allocation redevelopment plan. A
15 condemning authority may exercise the power of eminent domain
16 for the acquisition of property in furtherance of an existing
17 tax increment allocation redevelopment plan as provided for by
18 law in effect prior to the effective date of this Act.
19 As used in this subsection, "existing tax increment
20 allocation redevelopment plan" means a redevelopment plan that
21 was adopted under the Tax Increment Allocation Redevelopment
22 Act (Article 11, Division 74.4 of the Illinois Municipal Code)
23 prior to April 15, 2006 and for which property assembly costs
24 were, before that date, included as a budget line item in the
25 plan or described in the narrative portion of the plan as part
26 of the redevelopment project, but does not include (i) any
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1 additional area added to the redevelopment project area on or
2 after April 15, 2006, (ii) any subsequent extension of the
3 completion date of a redevelopment plan beyond the estimated
4 completion date established in that plan prior to April 15,
5 2006, (iii) any acquisition of property in a conservation area
6 for which the condemnation complaint is filed more than 12
7 years after the effective date of this Act, or (iv) any
8 acquisition of property in an industrial park conservation
9 area.
10 As used in this subsection, "conservation area" and
11 "industrial park conservation area" have the same meanings as
12 under Section 11-74.4-3 of the Illinois Municipal Code.
13 (b) If the exercise of eminent domain authority is to
14 acquire property for public ownership and control, then the
15 condemning authority must prove that (i) the acquisition of
16 the property is necessary for a public purpose and (ii) the
17 acquired property will be owned and controlled by the
18 condemning authority or another governmental entity.
19 (c) Except when the acquisition is governed by subsection
20 (b) or is primarily for one of the purposes specified in
21 subsection (d), (e), or (f) and the condemning authority
22 elects to proceed under one of those subsections, if the
23 exercise of eminent domain authority is to acquire property
24 for private ownership or control, or both, then the condemning
25 authority must prove by clear and convincing evidence that the
26 acquisition of the property for private ownership or control
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1 is (i) primarily for the benefit, use, or enjoyment of the
2 public and (ii) necessary for a public purpose.
3 An acquisition of property primarily for the purpose of
4 the elimination of blight is rebuttably presumed to be for a
5 public purpose and primarily for the benefit, use, or
6 enjoyment of the public under this subsection.
7 Any challenge to the existence of blighting factors
8 alleged in a complaint to condemn under this subsection shall
9 be raised within 6 months of the filing date of the complaint
10 to condemn, and if not raised within that time the right to
11 challenge the existence of those blighting factors shall be
12 deemed waived.
13 Evidence that the Illinois Commerce Commission has granted
14 a certificate or otherwise made a finding of public
15 convenience and necessity for an acquisition of property (or
16 any right or interest in property) for private ownership or
17 control (including, without limitation, an acquisition for
18 which the use of eminent domain is authorized under the Public
19 Utilities Act, the Telephone Company Act, or the Electric
20 Supplier Act) to be used for utility purposes creates a
21 rebuttable presumption that such acquisition of that property
22 (or right or interest in property) is (i) primarily for the
23 benefit, use, or enjoyment of the public and (ii) necessary
24 for a public purpose.
25 In the case of an acquisition of property (or any right or
26 interest in property) for private ownership or control to be
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1 used for utility, pipeline, or railroad purposes for which no
2 certificate or finding of public convenience and necessity by
3 the Illinois Commerce Commission is required, evidence that
4 the acquisition is one for which the use of eminent domain is
5 authorized under one of the following laws creates a
6 rebuttable presumption that the acquisition of that property
7 (or right or interest in property) is (i) primarily for the
8 benefit, use, or enjoyment of the public and (ii) necessary
9 for a public purpose:
10 (1) the Public Utilities Act,
11 (2) the Telephone Company Act,
12 (3) the Electric Supplier Act,
13 (4) the Railroad Terminal Authority Act,
14 (5) the Grand Avenue Railroad Relocation Authority
15 Act,
16 (6) the West Cook Railroad Relocation and Development
17 Authority Act,
18 (7) Section 4-505 of the Illinois Highway Code,
19 (8) Section 17 or 18 of the Railroad Incorporation
20 Act,
21 (9) Section 18c-7501 of the Illinois Vehicle Code.
22 (d) If the exercise of eminent domain authority is to
23 acquire property for private ownership or control and if the
24 primary basis for the acquisition is the elimination of blight
25 and the condemning authority elects to proceed under this
26 subsection, then the condemning authority must: (i) prove by a
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1 preponderance of the evidence that acquisition of the property
2 for private ownership or control is necessary for a public
3 purpose; (ii) prove by a preponderance of the evidence that
4 the property to be acquired is located in an area that is
5 currently designated as a blighted area or conservation area
6 under an applicable statute; (iii) if the existence of blight
7 or blighting factors is challenged in an appropriate motion
8 filed within 6 months after the date of filing of the complaint
9 to condemn, prove by a preponderance of the evidence that the
10 required blighting factors existed in the area so designated
11 (but not necessarily in the particular property to be
12 acquired) at the time of the designation under item (ii) or at
13 any time thereafter; and (iv) prove by a preponderance of the
14 evidence at least one of the following:
15 (A) that it has entered into an express written
16 agreement in which a private person or entity agrees to
17 undertake a development project within the blighted area
18 that specifically details the reasons for which the
19 property or rights in that property are necessary for the
20 development project;
21 (B) that the exercise of eminent domain power and the
22 proposed use of the property by the condemning authority
23 are consistent with a regional plan that has been adopted
24 within the past 5 years in accordance with Section 5-14001
25 of the Counties Code or Section 11-12-6 of the Illinois
26 Municipal Code or with a local land resource management
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1 plan adopted under Section 4 of the Local Land Resource
2 Management Planning Act; or
3 (C) that (1) the acquired property will be used in the
4 development of a project that is consistent with the land
5 uses set forth in a comprehensive redevelopment plan
6 prepared in accordance with the applicable statute
7 authorizing the condemning authority to exercise the power
8 of eminent domain and is consistent with the goals and
9 purposes of that comprehensive redevelopment plan, and (2)
10 an enforceable written agreement, deed restriction, or
11 similar encumbrance has been or will be executed and
12 recorded against the acquired property to assure that the
13 project and the use of the property remain consistent with
14 those land uses, goals, and purposes for a period of at
15 least 40 years, which execution and recording shall be
16 included as a requirement in any final order entered in
17 the condemnation proceeding.
18 The existence of an ordinance, resolution, or other
19 official act designating an area as blighted is not prima
20 facie evidence of the existence of blight. A finding by the
21 court in a condemnation proceeding that a property or area has
22 not been proven to be blighted does not apply to any other case
23 or undermine the designation of a blighted area or
24 conservation area or the determination of the existence of
25 blight for any other purpose or under any other statute,
26 including without limitation under the Tax Increment
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1 Allocation Redevelopment Act (Article 11, Division 74.4 of the
2 Illinois Municipal Code).
3 Any challenge to the existence of blighting factors
4 alleged in a complaint to condemn under this subsection shall
5 be raised within 6 months of the filing date of the complaint
6 to condemn, and if not raised within that time the right to
7 challenge the existence of those blighting factors shall be
8 deemed waived.
9 (e) If the exercise of eminent domain authority is to
10 acquire property for private ownership or control and if the
11 primary purpose of the acquisition is one of the purposes
12 specified in item (iii) of this subsection and the condemning
13 authority elects to proceed under this subsection, then the
14 condemning authority must prove by a preponderance of the
15 evidence that: (i) the acquisition of the property is
16 necessary for a public purpose; (ii) an enforceable written
17 agreement, deed restriction, or similar encumbrance has been
18 or will be executed and recorded against the acquired property
19 to assure that the project and the use of the property remain
20 consistent with the applicable purpose specified in item (iii)
21 of this subsection for a period of at least 40 years, which
22 execution and recording shall be included as a requirement in
23 any final order entered in the condemnation proceeding; and
24 (iii) the acquired property will be one of the following:
25 (1) included in the project site for a residential
26 project, or a mixed-use project including residential
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1 units, where not less than 20% of the residential units in
2 the project are made available, for at least 15 years, by
3 deed restriction, long-term lease, regulatory agreement,
4 extended use agreement, or a comparable recorded
5 encumbrance, to low-income households and very low-income
6 households, as defined in Section 3 of the Illinois
7 Affordable Housing Act;
8 (2) used primarily for public airport, road, parking,
9 or mass transportation purposes and sold or leased to a
10 private party in a sale-leaseback, lease-leaseback, or
11 similar structured financing;
12 (3) owned or used by a public utility or electric
13 cooperative for utility purposes;
14 (4) owned or used by a railroad for passenger or
15 freight transportation purposes;
16 (5) sold or leased to a private party that operates a
17 water supply, waste water, recycling, waste disposal,
18 waste-to-energy, or similar facility;
19 (6) sold or leased to a not-for-profit corporation
20 whose purposes include the preservation of open space, the
21 operation of park space, and similar public purposes;
22 (7) used as a library, museum, or related facility, or
23 as infrastructure related to such a facility;
24 (8) used by a private party for the operation of a
25 charter school open to the general public; or
26 (9) a historic resource, as defined in Section 3 of
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1 the Illinois State Agency Historic Resources Preservation
2 Act, a landmark designated as such under a local
3 ordinance, or a contributing structure within a local
4 landmark district listed on the National Register of
5 Historic Places, that is being acquired for purposes of
6 preservation or rehabilitation.
7 (f) If the exercise of eminent domain authority is to
8 acquire property for public ownership and private control and
9 if the primary purpose of the acquisition is one of the
10 purposes specified in item (iii) of this subsection and the
11 condemning authority elects to proceed under this subsection,
12 then the condemning authority must prove by a preponderance of
13 the evidence that: (i) the acquisition of the property is
14 necessary for a public purpose; (ii) the acquired property
15 will be owned by the condemning authority or another
16 governmental entity; and (iii) the acquired property will be
17 controlled by a private party that operates a business or
18 facility related to the condemning authority's operation of a
19 university, medical district, hospital, exposition or
20 convention center, mass transportation facility, or airport,
21 including, but not limited to, a medical clinic, research and
22 development center, food or commercial concession facility,
23 social service facility, maintenance or storage facility,
24 cargo facility, rental car facility, bus facility, taxi
25 facility, flight kitchen, fixed based operation, parking
26 facility, refueling facility, water supply facility, and
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1 railroad tracks and stations.
2 (f-5) For all acquisitions governed by subsection (c)
3 where the property, or any right or interest in property, is to
4 be used for utility purposes, and where the condemning
5 authority is an entity required to submit an integrated
6 resource plan under the Municipal and Cooperative Electric
7 Utility Planning and Transparency Act, the rebuttable
8 presumption described in subsection (c) shall only apply if
9 the most recent integrated resource plan filed by the
10 condemning authority identified the facility or articulated a
11 need for a facility of similar capacity and type to the
12 facility for which the property or right or interest is
13 sought.
14 (g) This Article is a limitation on the exercise of the
15 power of eminent domain, but is not an independent grant of
16 authority to exercise the power of eminent domain.
17 (Source: P.A. 94-1055, eff. 1-1-07.)
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1 INDEX
2 Statutes amended in order of appearance
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1 INDEX
2 Statutes amended in order of appearance
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