Illinois-2023-SB3637-Introduced

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.

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A BILL FOR

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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

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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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INDEX

Statutes amended in order of appearance