103RD GENERAL ASSEMBLY
State of Illinois
2023 and 2024
SB3637

 

Introduced 2/9/2024, by Sen. Bill Cunningham

 

SYNOPSIS AS INTRODUCED:
 
See Index

    Creates the Municipal and Cooperative Electric Utility Planning and Transparency Act. Provides that, by November 1, 2024, and by November 1 every 3 years thereafter, all electric cooperatives with members in the State, municipal power agencies, and municipalities shall file with the Illinois Power Agency an integrated resource plan. Sets forth provisions concerning the plan. Amends the Illinois Power Agency Act. Authorizes the Illinois Power Agency to develop capacity procurement plans and conduct competitive procurement processes for the procurement of capacity needed to ensure environmentally sustainable long-term resource adequacy across the State at the lowest cost over time. Amends the Public Utilities Act. Changes the cumulative persisting annual savings goals for electric utilities that serve less than 3,000,000 retail customers but more than 500,000 retail customers for the years of 2024 through 2030. Provides that the cumulative persisting annual savings goals beyond the year 2030 shall increase by 0.9 (rather than 0.6) percentage points per year. Changes the requirements for submitting proposed plans and funding levels to meet savings goals for an electric utility serving more than 500,000 retail customers (rather than serving less than 3,000,000 retail customers but more than 500,000 retail customers). Provides that an electric utility that has a tariff approved within one year of the amendatory Act shall also offer at least one market-based, time-of-use rate for eligible retail customers that choose to take power and energy supply service from the utility. Sets forth provisions regarding the Illinois Commerce Commission's powers and duties related to residential time-of-use pricing. Provides that each capacity procurement event may include the procurement of capacity through a mix of contracts with different terms and different initial delivery dates. Sets forth the requirements of prepared capacity procurement plans. Requires each alternative electric supplier to make payment to an applicable electric utility for capacity, receive transfers of capacity credits, report capacity credits procured on its behalf to the applicable regional transmission organization, and submit the capacity credits to the applicable regional transmission organization under that regional transmission organization's rules and procedures. Makes other changes.


LRB103 38841 CES 68978 b

 

 

A BILL FOR

 

SB3637LRB103 38841 CES 68978 b

1    AN ACT concerning regulation.
 
2    Be it enacted by the People of the State of Illinois,
3represented in the General Assembly:
 
4    Section 1. Short title. This Act may be cited as the
5Municipal and Cooperative Electric Utility Planning and
6Transparency Act.
 
7    Section 5. Legislative findings and objectives. The
8General 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
18behalf of a utility to reduce retail customer consumption
19(MWh) or shift the time of consumption of energy (MW) from end
20users, including energy efficiency programs, demand-response
21programs, and programs for the promotion or aggregation of
22distributed generation.
23    "Electric cooperative" has the meaning given to that term
24in Section 3-119 of the Public Utilities Act.
25    "Generation resource" means a facility for the generation

 

 

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1of electricity.
2    "Municipal power agency" has the meaning given to that
3term in Section 11-119.1-3 of the Illinois Municipal Code.
4    "Municipality" has the meaning given to that term in
5Section 11-119.1-3 of the Illinois Municipal Code.
6    "Renewable generation resource" means a resource for
7generating electricity that uses wind, solar, or geothermal
8energy.
9    "Storage resource" means a commercially available
10technology that uses mechanical, chemical, or thermal
11processes to store energy and deliver the stored energy as
12electricity for use at a later time and is capable of being
13controlled by the distribution or transmission entity managing
14it, to enable and optimize the safe and reliable operation of
15the electric system.
16    "Utility" means a municipal power agency, municipality, or
17electric cooperative.
 
18    Section 15. Purpose and contents of integrated resource
19plan.
20    (a) By November 1, 2024, and by November 1 every 3 years
21thereafter, all electric cooperatives with members in this
22State, municipal power agencies, and municipalities shall file
23with the Agency an integrated resource plan, except that
24municipalities and electric cooperatives that are members of,
25and have a full requirements contract with, a municipal power

 

 

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1agency or electric cooperative subject to this Act may file a
2statement adopting such other utility's integrated resource
3plan.
4    (b) The purposes of the integrated resource plan are to
5provide a comprehensive description of the utility's current
6portfolio of electrical generation, storage, demand-side
7programs, and transmission resources, to forecast future load
8changes to facilitate prudent planning with respect to
9resource procurement and retirement, to determine what
10resource portfolio will meet ratepayers' needs while
11minimizing cost and environmental impact, and to articulate
12steps the utility will take to reduce customer costs and
13environmental impacts through changes to its current
14generation portfolio through construction, procurement,
15retirement, or demand-side programs.
16    (c) As part of the integrated resource plan development
17process, a utility shall consider all resources reasonably
18available or reasonably likely to be available during the
19relevant time period to satisfy the demand for electricity
20services for a 20-year planning period, taking into account
21both supply-side and demand-side electric power resources.
22    (d) An integrated resource plan shall include, at a
23minimum:
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
122024, the utility shall identify all programs, grants, loans,
13or tax benefits for which the utility is eligible pursuant to
14the Inflation Reduction Act of 2022, and state whether the
15utility has applied for or otherwise used the program, grant,
16loan, or tax benefit. If the utility has not yet applied for or
17utilized the benefit, the utility shall state whether it
18intends to do so.
19    (f) Each utility shall submit, as part of its integrated
20resource plan, a least cost plan for constructing or procuring
21renewable energy resources to meet a minimum percentage of its
22load for all retail customers as follows: 25% by June 1, 2026,
23increasing by at least 3% each delivery year thereafter to at
24least 40% by the 2030 delivery year, and continuing at no less
25than 40% for each delivery year thereafter.
26    (g) Beginning in 2031, each utility shall submit, as part

 

 

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1of its integrated resource plan, a least cost plan for
2supplying 100% of its total projected load through renewable
3generation resources in combination with storage resources and
4demand-side programs by 2045. This least cost plan shall
5provide for the retirement of all coal and gas generation
6resources by January 1, 2045.
7    (h) The Agency may adopt rules establishing additional
8requirements as to the form and content of integrated resource
9plans, including, but not limited to, specifying forecast
10methodologies.
 
11    Section 20. Stakeholder process. Prior to the submission
12of an integrated resource plan, a municipality, municipal
13power agency, or electric cooperative required to submit an
14integrated resource plan shall hold at least 2 stakeholders
15meetings open to all ratepayers and members of the public.
16Notice of the meetings shall be sent to all customers not less
17than 30 days prior to the meeting. During the meetings the
18utility shall describe its processes for developing the
19integrated resource plan and its core assumptions and
20constraints, present its proposed preferred portfolio, and
21describe any planned retirements, capital expenditures on
22existing generation resources likely to exceed $1,000,000, and
23planned construction. Each meeting shall allow time for public
24comment and the utility shall provide attendees with a means
25of providing public comment in writing following the meeting.
 

 

 

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1    Section 25. Procedures for submission of integrated
2resource plan.
3    (a) Each municipality, municipal power agency, and
4electric cooperative shall submit its integrated resource
5plan, as set forth in this Act, to the Agency by October 1 of
6the calendar year.
7    (b) The Agency may request further information from the
8utility. Any such requests shall be made in writing. If the
9Agency requests additional information, the utility shall
10provide responses no later than 15 days following the request.
11    (c) The Agency shall facilitate public comment on the
12integrated 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
7responses that reasonably address all issues or questions
8raised by such comments. The utility may modify its integrated
9resource plan in response to these comments. The utility shall
10prepare a document with responses to public comments and
11submit this response document to the Agency no later than 90
12days after receiving the comments from the agency. This
13response document shall be posted publicly on the Agency's
14website along with the original integrated resource plan, as
15submitted, and any revisions made by the utility in response
16to public comments.
17    (e) The Agency shall maintain public access to all
18integrated resource plans submitted pursuant to this Act,
19accessible through the Agency's website, for no less than 10
20years following each integrated resource plan's initial
21submission.
 
22    Section 30. Cost of Service Study.
23    (a) All electric cooperatives with members in this State,
24municipal power agencies, and municipalities with $5,000,000
25or more in total retail electricity revenues shall submit to

 

 

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1the Agency an embedded cost-of-service study on November 1,
22024 and on November 1 every 3 years thereafter.
3    (b) The format and contents of such study shall be
4consistent with those set forth in any rules or regulations by
5the Illinois Commerce Commission for cost-of-service studies
6by electric utilities subject to retail rate approval by the
7Commerce Commission.
 
8    Section 35. Use of independent expert.
9    (a) The Agency shall maintain a list of qualified experts
10or expert consulting firms for the purpose of developing
11integrated resource plans on behalf of municipalities,
12municipal power agencies, and cooperatives. In order to
13qualify 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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1for developing a list of qualified experts for experts to
2develop procurement plans, as set forth in subsection (a) of
3Section 1-75 of the Illinois Power Agency Act.
4    (c) The Agency shall provide affected utilities and other
5interested parties with the lists of qualified experts or
6expert consulting firms identified through the request for
7qualifications processes that are under consideration to
8prepare the integrated resource plan on behalf of the utility.
9The Agency shall also provide each qualified expert's or
10expert consulting firm's response to the request for
11qualifications. A utility shall, within 5 business days,
12notify the Agency in writing if it objects to any experts or
13expert consulting firms on the lists. Objections shall be
14based 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
20from the lists within 10 days if there is a reasonable basis
21for an objection and provide the updated lists to the affected
22utilities and other interested parties. If the Agency fails to
23remove an expert or expert consulting firm from the list, the
24objecting utility may withdraw its application and develop its
25integrated resource plan without agency assistance.
26    (d) A utility required to submit an integrated resource

 

 

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1plan may elect to rely on an expert or expert consulting firm
2selected by the Agency to develop the plan and conduct
3stakeholder processes.
4    (e) A utility may submit a request to the Agency, not less
5than 6 months prior to the date on which the integrated
6resource plan is due, for such an expert or expert consulting
7firm.
8    (f) Upon receipt of such a request, the Agency shall issue
9requests for proposals to the qualified experts on the list
10assembled as set forth in subsections (a) through (c) to
11develop an integrated resource plan for that utility. The
12Agency shall select an expert or expert consulting firm to
13develop the integrated resource plan on behalf of the utility
14based on the proposals submitted.
15    (g) Subject to appropriation, if a utility elects to rely
16on an expert or expert consulting firm selected by the Agency,
1790% of the costs assessed by the expert for development of the
18integrated 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
22given 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
25accordance with the cooperative's bylaws. Where a generation

 

 

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1and transmission electric cooperative's members are electric
2cooperatives rather than individuals, members of those
3member-cooperatives are members of the generation and
4transmission electric cooperative for purposes of this
5Section. As used in subsection (j), "member" includes only
6members of an electric cooperative with individual members.
7    (c) All meetings of an electric cooperative shall be open
8to all members, except that a cooperative, by a two-thirds
9affirmative vote of the board members present, may go into
10executive session for consideration of documents or
11information deemed to be confidential for legal, commercial,
12or 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
10its current rates. The electric cooperative shall keep and
11make available to any member, upon request, all financial
12audits of the electric cooperative conducted in the last 3
13fiscal years.
14    (e) Each electric cooperative shall adopt and post a
15written policy governing the election of directors on its
16website. The electric cooperative shall provide notice of the
17policy at the time a person becomes a member, as a bill insert
18at least once per year, and on request. The policy shall
19contain 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
2vote in any election for one or more directors by mail-in
3ballot, 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
14online voting in addition to a mail-in option.
15    (h) At least 120 days before each board election, the
16electric cooperative shall post a list of candidates and
17deadline to return ballots on its website and leave the
18information posted until the election has concluded. The same
19information shall be included as part of a bill insert for a
20billing cycle occurring at no more than 120 but no fewer than
2115 days prior to the deadline to return ballots.
22    (i) Each candidate for a position on the board of
23directors who has qualified under the electric cooperative's
24bylaws is entitled to receive a membership list in electronic
25format upon receipt and verification of any candidacy
26requirements. Such a list shall be provided to a candidate no

 

 

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1later than 15 days after requested by the candidate. The
2membership list must include the names, phone numbers, and
3addresses of all members as they appear in the electric
4cooperative's records.
 
5    Section 45. Conflict of interest.
6    (a) Each electric cooperative, municipality, and municipal
7power agency shall adopt, and post publicly on its website,
8written 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
7website all lobbying activities as defined by Section 2 of the
8Lobbyist Registration Act and the amount of expenditures on
9such activities on an annual basis. Where the electric
10cooperative is a member of a trade association or other
11organization that engages in lobbying activities, the electric
12cooperative shall post the amount of dues or other
13expenditures paid by the cooperative to such an organization
14and what percentage of the organization or association's
15budget is spent on lobbying activities.
16    (c) Notwithstanding any other law to the contrary, if an
17individual is a director on the board of directors of both a
18distribution cooperative electric association and a generation
19and transmission cooperative association, the director owes
20fiduciary duties to both associations and shall not be
21required to give priority to a fiduciary duty the director
22owes to one association over the duties the director owes to
23the other association.
 
24    Section 90. The Open Meetings Act is amended by changing
25Section 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
4be open to the public unless excepted in subsection (c) and
5closed in accordance with Section 2a.
6    (b) Construction of exceptions. The exceptions contained
7in subsection (c) are in derogation of the requirement that
8public bodies meet in the open, and therefore, the exceptions
9are to be strictly construed, extending only to subjects
10clearly within their scope. The exceptions authorize but do
11not require the holding of a closed meeting to discuss a
12subject included within an enumerated exception.
13    (c) Exceptions. A public body may hold closed meetings to
14consider 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
8relationship with the public body constitutes an
9employer-employee relationship under the usual common law
10rules, and who is not an independent contractor.
11    "Public office" means a position created by or under the
12Constitution or laws of this State, the occupant of which is
13charged with the exercise of some portion of the sovereign
14power of this State. The term "public office" shall include
15members of the public body, but it shall not include
16organizational positions filled by members thereof, whether
17established by law or by a public body itself, that exist to
18assist the body in the conduct of its business.
19    "Quasi-adjudicative body" means an administrative body
20charged by law or ordinance with the responsibility to conduct
21hearings, receive evidence or testimony and make
22determinations based thereon, but does not include local
23electoral boards when such bodies are considering petition
24challenges.
25    (e) Final action. No final action may be taken at a closed
26meeting. Final action shall be preceded by a public recital of

 

 

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1the nature of the matter being considered and other
2information that will inform the public of the business being
3conducted.
4(Source: P.A. 102-237, eff. 1-1-22; 102-520, eff. 8-20-21;
5102-558, eff. 8-20-21; 102-813, eff. 5-13-22; 103-311, eff.
67-28-23.)
 
7    Section 95. The Illinois Power Agency Act is amended by
8changing Sections 1-5 and 1-20 as follows:
 
9    (20 ILCS 3855/1-5)
10    Sec. 1-5. Legislative declarations and findings. The
11General 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
21to create the Illinois Power Agency and that the goals and
22objectives of that Agency are to accomplish each of the
23following:
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
15has all of the powers necessary or convenient to carry out the
16purposes and provisions of this Act, including without
17limitation, 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
19products, beginning January 1, 2022, the Agency shall not
20procure any products or services from persons or organizations
21that are in violation of the Displaced Energy Workers Bill of
22Rights, as provided under the Energy Community Reinvestment
23Act at the time of the procurement event or fail to comply the
24labor 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
2changing Sections 11-119.1-4 and 11-119.1-10 and by adding
3Section 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
7noncontiguous, and which operate an electric utility system,
8may form a municipal power agency by the execution of an agency
9agreement authorized by an ordinance adopted by the governing
10body 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
19municipal power agency established pursuant to this Division
20or such other officer selected by the Board of Directors,
21within 3 months after establishment, shall file a certified
22copy of the agency agreement and a list of the municipalities
23which have adopted the agreement with the recorder of deeds of
24the county in which the principal office is located. The
25recorder of deeds shall record this certified copy and list
26and shall immediately transmit the certified copy and list to

 

 

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1the Secretary of State, together with his certificate of
2recordation. The Secretary of State shall file these documents
3and issue his certificate of approval over his signature and
4the Great Seal of the State. The Secretary of State shall make
5and keep a register of municipal power agencies established
6under this Division.
7    C. Each municipality which becomes a member of the
8municipal power agency shall appoint a representative to serve
9on the Board of Directors, which representative may be a
10member of the governing body of the municipality. Each
11appointment shall be made by the mayor, or president, subject
12to the confirmation of the governing body. The directors so
13appointed shall hold office for a term of 3 years, or until a
14successor has been duly appointed and qualified, except that
15the directors first appointed shall determine by lot at their
16initial meeting the respective directors which shall serve for
17a term of one, 2 or 3 years from the date of that meeting. A
18vacancy shall be filled for the balance of the unexpired term
19in the same manner as the original appointment.
20    The Board of Directors is the corporate authority of the
21municipal power agency and shall exercise all the powers and
22manage and control all of the affairs and property of the
23agency. The Board of Directors shall have full power to pass
24all necessary ordinances, resolutions, rules and regulations
25for the proper management and conduct of the business of the
26board, and for carrying into effect the objects for which the

 

 

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1agency was established.
2    At the initial meeting of the Board of Directors to be held
3within 30 days after the date of establishment of the
4municipal power agency, the directors shall elect from their
5members a presiding officer to preside over the meetings of
6the Board of Directors and an alternative presiding officer
7and may elect an executive board. The Board of Directors shall
8determine and designate in the agency's bylaws the titles for
9the presiding officers. The directors shall also elect a
10secretary and treasurer, who need not be directors. The board
11may select such other officers, employees and agents as deemed
12to be necessary, who need not be directors or residents of any
13of the municipalities which are members of the municipal power
14agency. The board may designate appropriate titles for all
15other officers, employees, and agents. All persons selected by
16the board shall hold their respective offices during the
17pleasure of the board, and give such bond as may be required by
18the board.
19    D. The bylaws of the municipal power agency, and any
20amendments thereto, shall be adopted by the Board of Directors
21by a majority vote (adjusted for weighted voting, if provided
22in 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
13in the State of Illinois to be known as its principal office.
14When a municipal power agency desires to change the location
15of such office, it shall file with the Secretary of State a
16certificate of change of location, stating the new address and
17the effective date of change. Meetings of the Board of
18Directors may be held at any place within the State of
19Illinois, designated by the Board of Directors, after notice.
20Unless otherwise provided by the bylaws, an act of the
21majority of the directors present at a meeting at which a
22quorum is present is the act of the Board of Directors.
23    F. The Board of Directors shall hold at least one meeting
24each year for the election of officers and for the transaction
25of any other business. Special meetings of the Board of
26Directors may be called for any purpose upon written request

 

 

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1to the presiding officer of the Board of Directors or
2secretary to call the meeting. Such officer shall give notice
3of the meeting to be held not less than 10 days and not more
4than 60 days after receipt of such request. Unless the bylaws
5provide for a different percentage, a quorum for a meeting of
6the Board of Directors is a majority of all members then in
7office. All meetings of the board shall be held in compliance
8with the provisions of "An Act in relation to meetings",
9approved July 11, 1957, as amended.
10    G. The agency agreement may be amended as proposed at any
11meeting of the Board of Directors for which notice, stating
12the purpose, shall be given to each director and, unless the
13bylaws prescribe otherwise, such amendment shall become
14effective when ratified by ordinances adopted by a majority of
15the governing bodies of the member municipalities. Each
16amendment, duly certified, shall be recorded and filed in the
17same manner as for the original agreement.
18    H. Each member municipality shall have full power and
19authority, subject to the provisions of its charter and laws
20regarding local finance, to appropriate money for the payment
21of the expenses of the municipal power agency and of its
22representative in exercising its functions as a member of the
23municipal power agency.
24    I. Any additional municipality which operates an electric
25utility system may join the municipal power agency, or any
26member municipality may withdraw therefrom consistent with the

 

 

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1bylaws of the municipal power agency, and upon payment of any
2termination obligations as described in subsection D upon the
3approval by ordinance adopted by the governing body of the
4majority of the municipalities which are then members of the
5municipal power agency. Any new member shall agree to assume
6its proportionate share of the outstanding obligations of the
7municipal power agency and any member permitted to withdraw
8shall remain obligated to make payments under any outstanding
9contract or agreement with the municipal power agency or to
10comply with any exit or early termination provisions set forth
11in that contract or agreement. Any such change in membership
12shall be recorded and filed in the same manner as for the
13original agreement.
14    J. Any 2 or more municipal power agencies organized
15pursuant to this Division may consolidate to form a new
16municipal power agency when approved by ordinance adopted by
17the governing body of each municipality which is a member of
18the respective municipal power agency and by the execution of
19an 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
23reports.
24    (a) A municipal power agency shall keep accurate accounts
25and records of its assets, liabilities, revenues, and

 

 

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1expenditures in accordance with generally accepted accounting
2principles. Such accounts and records shall include, but are
3not limited to, depreciation, operating and maintenance
4expenses for all generation and transmission assets, fuel
5costs, cost and revenue from the purchase or sale of
6environmental compliance credits, revenue from energy,
7capacity, and ancillary market sales, all payments received
8from member municipalities, membership dues or other payments
9made to trade associations or industry organizations, and
10lobbying expenditures. Such records shall be audited on an
11annual basis by an independent auditor using generally
12accepted auditing standards and shall include contents as set
13forth in Section 8-8-5, and shall be filed with the
14Comptroller as described by Section 8-8-7.
15    (b) A municipal power agency shall, on an annual basis,
16prepare one-year and 5-year budgets that include all revenues
17and expenses, including, but not limited to, those categories
18described in subsection (a). As part of each one-year budget,
19the municipal power agency shall include a report identifying
20and explaining any variance from the previous annual budget of
215% or greater in any expenditure or revenue line item. Such
22budgets shall be provided to member municipalities no less
23than 60 days prior to any meeting of the municipal power agency
24during which action on the budget is or will be part of the
25agency agenda.
26    (c) The municipal power agency shall post, on a publicly

 

 

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1available website, all one-year and 5-year budgets required
2under subsection (b) and the annual audited financial
3statements required under subsection (a).
4    (d) The municipal power agency shall make available, upon
5request to any of its member municipalities, access to all
6municipal power agency all records and accounts and all
7financial information relating to ownership and operation of
8agency assets and the generation, procurement, and delivery of
9electricity to which the agency has access, including, but not
10limited to, unit scheduling information, market revenue and
11off-system sales data, and fuel and other variable cost
12information. Such information shall be provided in a timely
13manner and through reasonable means, and members shall be
14permitted to make copies of any documents retained solely by
15the agency. Such access shall be provided without regard to
16any nondisclosure agreement that has been or may be adopted by
17the municipal power agency.
18    (e) The municipal power agency shall prepare, on a
19quarterly basis, a report to its member municipalities
20describing all expenditures made for the purpose of lobbying,
21as both terms are defined by Section 2 of the Lobbyist
22Registration Act, and a brief summary of the topics and
23positions on which lobbying activities were undertaken. Where
24the municipal power agency is a member of an organization or
25trade association that expends some or all of membership dues
26on lobbying activities, the municipal power agency shall

 

 

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1include in this report the amount of those membership dues,
2what proportion of those dues were spent on lobbying
3activities, and the topics and positions on which lobbying
4activities were undertaken by the organization or trade
5association 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
8agency may exercise any and all of the powers enumerated in
9this Division, except the power of eminent domain, without the
10consent and approval of the Illinois Commerce Commission. The
11exercise of the power of eminent domain by a municipal power
12agency shall be subject to the consent and approval of the
13Illinois Commerce Commission in the same manner and to the
14same extent as public utilities under the Public Utilities
15Act, including the issuance of a certificate of public
16convenience and necessity as provided for in Section 8-406 of
17that Act. During the consideration of any petition for
18authority to exercise the power of eminent domain the Illinois
19Commerce Commission shall evaluate and give due consideration
20to whether the project for which eminent domain is sought is
21part of the preferred portfolio as described in subsection (d)
22of Section 15 of the Municipal and Cooperative Electric
23Utility Planning and Transparency Act, or least cost plans for
24procuring renewable resources as described in subsections (f)
25and (g) of Section 20 of the Municipal and Cooperative

 

 

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1Electric Utility Planning and Transparency Act and to the
2impact of the acquisition on farmlands in the State with the
3goal of preserving the land to the fullest extent reasonably
4possible.
5(Source: P.A. 90-416, eff. 1-1-98.)
 
6    Section 105. The Public Utilities Act is amended by
7changing Sections 3-105, 8-103B, 16-107.5, 16-111.5, 16-115A,
816-115D, 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
12otherwise expressly provided in this Section, every
13corporation, company, limited liability company, association,
14joint stock company or association, firm, partnership or
15individual, their lessees, trustees, or receivers appointed by
16any court whatsoever now or hereafter that owns, controls,
17operates or manages, within this State, directly or
18indirectly, for public use, any plant, equipment or property
19used or to be used for or in connection with, or owns or
20controls or seeks Commission approval to own or control any
21franchise, 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
20electric vehicles does not and shall not be deemed to sell
21electricity and is not and shall not be deemed a public utility
22notwithstanding the basis on which the service is provided or
23billed. If, however, the entity is otherwise deemed a public
24utility under this Act, or is otherwise subject to regulation
25under this Act, then that entity is not exempt from and remains
26subject to the otherwise applicable provisions of this Act.

 

 

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1The installation, maintenance, and repair of an electric
2vehicle charging station shall comply with the requirements of
3subsection (a) of Section 16-128 and Section 16-128A of this
4Act.
5    For purposes of this subsection, the term "electric
6vehicles" has the meaning ascribed to that term in Section 10
7of 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
11measures.
12    (a) It is the policy of the State that electric utilities
13are required to use cost-effective energy efficiency and
14demand-response measures to reduce delivery load. Requiring
15investment in cost-effective energy efficiency and
16demand-response measures will reduce direct and indirect costs
17to consumers by decreasing environmental impacts and by
18avoiding or delaying the need for new generation,
19transmission, and distribution infrastructure. It serves the
20public interest to allow electric utilities to recover costs
21for reasonably and prudently incurred expenditures for energy
22efficiency and demand-response measures. As used in this
23Section, "cost-effective" means that the measures satisfy the
24total resource cost test. The low-income measures described in
25subsection (c) of this Section shall not be required to meet

 

 

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1the total resource cost test. For purposes of this Section,
2the terms "energy-efficiency", "demand-response", "electric
3utility", and "total resource cost test" have the meanings set
4forth in the Illinois Power Agency Act. "Black, indigenous,
5and people of color" and "BIPOC" means people who are members
6of the groups described in subparagraphs (a) through (e) of
7paragraph (A) of subsection (1) of Section 2 of the Business
8Enterprise for Minorities, Women, and Persons with
9Disabilities Act.
10    (a-5) This Section applies to electric utilities serving
11more than 500,000 retail customers in the State for those
12multi-year plans commencing after December 31, 2017.
13    (b) For purposes of this Section, through calendar year
142025, electric utilities subject to this Section that serve
15more than 3,000,000 retail customers in the State shall be
16deemed to have achieved a cumulative persisting annual savings
17of 6.6% from energy efficiency measures and programs
18implemented during the period beginning January 1, 2012 and
19ending December 31, 2017, which percent is based on the deemed
20average weather normalized sales of electric power and energy
21during calendar years 2014, 2015, and 2016 of 88,000,000 MWhs.
22For the purposes of this subsection (b) and subsection (b-5),
23the 88,000,000 MWhs of deemed electric power and energy sales
24shall be reduced by the number of MWhs equal to the sum of the
25annual consumption of customers that have opted out of
26subsections (a) through (j) of this Section under paragraph

 

 

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1(1) of subsection (l) of this Section, as averaged across the
2calendar years 2014, 2015, and 2016. After 2017, the deemed
3value of cumulative persisting annual savings from energy
4efficiency measures and programs implemented during the period
5beginning January 1, 2012 and ending December 31, 2017, shall
6be reduced each year, as follows, and the applicable value
7shall be applied to and count toward the utility's achievement
8of the cumulative persisting annual savings goals set forth in
9subsection (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
6annual savings" means the total electric energy savings in a
7given year from measures installed in that year or in previous
8years, but no earlier than January 1, 2012, that are still
9operational and providing savings in that year because the
10measures have not yet reached the end of their useful lives.
11    (b-5) Beginning in 2018, through calendar year 2025,
12electric utilities subject to this Section that serve more
13than 3,000,000 retail customers in the State shall achieve the
14following cumulative persisting annual savings goals, as
15modified by subsection (f) of this Section and as compared to
16the deemed baseline of 88,000,000 MWhs of electric power and
17energy sales set forth in subsection (b), as reduced by the
18number of MWhs equal to the sum of the annual consumption of
19customers that have opted out of subsections (a) through (j)
20of this Section under paragraph (1) of subsection (l) of this
21Section as averaged across the calendar years 2014, 2015, and
222016, through the implementation of energy efficiency measures
23during the applicable year and in prior years, but no earlier
24than 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
26Commission shall establish additional cumulative persisting

 

 

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1annual savings goals for the years 2031 through 2035. No later
2than December 31, 2024, the Illinois Commerce Commission shall
3establish additional cumulative persisting annual savings
4goals for the years 2036 through 2040. The Commission shall
5also establish additional cumulative persisting annual savings
6goals every 5 years thereafter to ensure that utilities always
7have goals that extend at least 11 years into the future. The
8cumulative persisting annual savings goals beyond the year
92030 shall increase by 0.9 percentage points per year, absent
10a Commission decision to initiate a proceeding to consider
11establishing goals that increase by more or less than that
12amount. Such a proceeding must be conducted in accordance with
13the procedures described in subsection (f) of this Section. If
14such a proceeding is initiated, the cumulative persisting
15annual savings goals established by the Commission through
16that proceeding shall reflect the Commission's best estimate
17of the maximum amount of additional savings that are forecast
18to be cost-effectively achievable unless such best estimates
19would result in goals that represent less than 0.5 percentage
20point annual increases in total cumulative persisting annual
21savings. The Commission may only establish goals that
22represent less than 0.5 percentage point annual increases in
23cumulative persisting annual savings if it can demonstrate,
24based on clear and convincing evidence and through independent
25analysis, that 0.5 percentage point increases are not
26cost-effectively achievable. The Commission shall inform its

 

 

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1decision based on an energy efficiency potential study that
2conforms to the requirements of this Section.
3    (b-10) For purposes of this Section, through calendar year
42025, electric utilities subject to this Section that serve
5less than 3,000,000 retail customers but more than 500,000
6retail customers in the State shall be deemed to have achieved
7a cumulative persisting annual savings of 6.6% from energy
8efficiency measures and programs implemented during the period
9beginning January 1, 2012 and ending December 31, 2017, which
10is based on the deemed average weather normalized sales of
11electric power and energy during calendar years 2014, 2015,
12and 2016 of 36,900,000 MWhs. For the purposes of this
13subsection (b-10) and subsection (b-15), the 36,900,000 MWhs
14of deemed electric power and energy sales shall be reduced by
15the number of MWhs equal to the sum of the annual consumption
16of customers that have opted out of subsections (a) through
17(j) of this Section under paragraph (1) of subsection (l) of
18this Section, as averaged across the calendar years 2014,
192015, and 2016. After 2017, the deemed value of cumulative
20persisting annual savings from energy efficiency measures and
21programs implemented during the period beginning January 1,
222012 and ending December 31, 2017, shall be reduced each year,
23as follows, and the applicable value shall be applied to and
24count toward the utility's achievement of the cumulative
25persisting 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
23this Section that serve less than 3,000,000 retail customers
24but more than 500,000 retail customers in the State shall
25achieve the following cumulative persisting annual savings
26goals, as modified by subsection (b-20) and subsection (f) of

 

 

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1this Section and as compared to the deemed baseline as reduced
2by the number of MWhs equal to the sum of the annual
3consumption of customers that have opted out of subsections
4(a) through (j) of this Section under paragraph (1) of
5subsection (l) of this Section as averaged across the calendar
6years 2014, 2015, and 2016, through the implementation of
7energy efficiency measures during the applicable year and in
8prior 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
10Commission shall establish additional cumulative persisting
11annual savings goals for the years 2031 through 2035. No later
12than December 31, 2024, the Illinois Commerce Commission shall
13establish additional cumulative persisting annual savings
14goals for the years 2036 through 2040. The Commission shall
15also establish additional cumulative persisting annual savings
16goals every 5 years thereafter to ensure that utilities always
17have goals that extend at least 11 years into the future. The
18cumulative persisting annual savings goals beyond the year
192030 shall increase by 0.9 0.6 percentage points per year,
20absent a Commission decision to initiate a proceeding to
21consider establishing goals that increase by more or less than
22that amount. Such a proceeding must be conducted in accordance
23with the procedures described in subsection (f) of this
24Section. If such a proceeding is initiated, the cumulative
25persisting annual savings goals established by the Commission
26through that proceeding shall reflect the Commission's best

 

 

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1estimate of the maximum amount of additional savings that are
2forecast to be cost-effectively achievable unless such best
3estimates would result in goals that represent less than 0.5
40.4 percentage point annual increases in total cumulative
5persisting annual savings. The Commission may only establish
6goals that represent less than 0.5 0.4 percentage point annual
7increases in cumulative persisting annual savings if it can
8demonstrate, based on clear and convincing evidence and
9through independent analysis, that 0.5 0.4 percentage point
10increases are not cost-effectively achievable. The Commission
11shall inform its decision based on an energy efficiency
12potential study that conforms to the requirements of this
13Section.
14    (b-16) Beginning in 2026, and in every subsequent year,
15each electric utility subject to this Section shall achieve
16incremental annual savings equal to 2.25% of the utility's
17average annual electricity sales in the second, third, and
18fourth years prior to the start of each applicable multi-year
19energy efficiency planning period referenced in subsection
20(f), with an average savings life of at least 13 years. For the
21purposes of this Section, "incremental annual savings" means
22the total electric savings from all measures installed in a
23calendar year that will be realized within 12 months of each
24measure's installation. In no event can more than one-fifth of
25the incremental annual savings counted towards a utility's
26annual savings goal in any given year be derived from

 

 

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1efficiency measures with average savings lives of less than 5
2years.
3    (b-20) Each electric utility subject to this Section may
4include cost-effective voltage optimization measures in its
5plans submitted under subsections (f) and (g) of this Section,
6and the costs incurred by a utility to implement the measures
7under a Commission-approved plan shall be recovered under the
8provisions of Article IX or Section 16-108.5 of this Act. For
9purposes of this Section, the measure life of voltage
10optimization measures shall be 15 years. The measure life
11period is independent of the depreciation rate of the voltage
12optimization assets deployed. Utilities may claim savings from
13voltage optimization on circuits for more than 15 years if
14they can demonstrate that they have made additional
15investments necessary to enable voltage optimization savings
16to continue beyond 15 years. Such demonstrations must be
17subject to the review of independent evaluation.
18    Within 270 days after June 1, 2017 (the effective date of
19Public Act 99-906), an electric utility that serves less than
203,000,000 retail customers but more than 500,000 retail
21customers in the State shall file a plan with the Commission
22that identifies the cost-effective voltage optimization
23investment the electric utility plans to undertake through
24December 31, 2024. The Commission, after notice and hearing,
25shall approve or approve with modification the plan within 120
26days after the plan's filing and, in the order approving or

 

 

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1approving with modification the plan, the Commission shall
2adjust the applicable cumulative persisting annual savings
3goals set forth in subsection (b-15) to reflect any amount of
4cost-effective energy savings approved by the Commission that
5is greater than or less than the following cumulative
6persisting annual savings values attributable to voltage
7optimization 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
26energy efficiency measure or program with a gas utility under

 

 

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1plans approved under this Section and Section 8-104 of this
2Act, the electric utility may continue offering the program,
3including the gas energy efficiency measures, in the event the
4gas utility discontinues funding the program. In that event,
5the energy savings value associated with such other fuels
6shall be converted to electric energy savings on an equivalent
7Btu basis for the premises. However, the electric utility
8shall prioritize programs for low-income residential customers
9to the extent practicable. An electric utility may recover the
10costs of offering the gas energy efficiency measures under
11this subsection (b-25).
12    For those energy efficiency measures or programs that save
13both electricity and other fuels but are not jointly offered
14with a gas utility under plans approved under this Section and
15Section 8-104 or not offered with an affiliated gas utility
16under paragraph (6) of subsection (f) of Section 8-104 of this
17Act, the electric utility may count savings of fuels other
18than electricity toward the achievement of its annual savings
19goal, and the energy savings value associated with such other
20fuels shall be converted to electric energy savings on an
21equivalent Btu basis at the premises.
22    In no event shall more than 10% of each year's applicable
23annual total savings requirement as defined in paragraph (7.5)
24of subsection (g) of this Section, or more than 10% of each
25year's incremental annual savings as defined in subsection
26(b-16) be met through savings of fuels other than electricity.

 

 

SB3637- 77 -LRB103 38841 CES 68978 b

1    (b-27) Beginning in 2022, an electric utility may offer
2and promote measures that electrify space heating, water
3heating, cooling, drying, cooking, industrial processes, and
4other building and industrial end uses that would otherwise be
5served by combustion of fossil fuel at the premises, provided
6that the electrification measures reduce total energy
7consumption at the premises. The electric utility may count
8the reduction in energy consumption at the premises toward
9achievement of its annual savings goals. The reduction in
10energy consumption at the premises shall be calculated as the
11difference between: (A) the reduction in Btu consumption of
12fossil fuels as a result of electrification, converted to
13kilowatt-hour equivalents by dividing by 3,412 Btus per
14kilowatt hour; and (B) the increase in kilowatt hours of
15electricity consumption resulting from the displacement of
16fossil fuel consumption as a result of electrification. An
17electric utility may recover the costs of offering and
18promoting electrification measures under this subsection
19(b-27). At least 40% of all such costs must be for supporting
20installation of electrification measures in low income
21housing.
22    In no event shall electrification savings counted toward
23each year's applicable annual total savings requirement, as
24defined in paragraph (7.5) of subsection (g) of this Section,
25be greater than:
26        (1) 5% per year for each year from 2022 through 2025;

 

 

SB3637- 78 -LRB103 38841 CES 68978 b

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.
4In addition, a minimum of 25% of all electrification savings
5counted toward a utility's applicable annual total savings
6requirement must be from electrification of end uses in
7low-income housing. The limitations on electrification savings
8that may be counted toward a utility's annual savings goals
9are separate from and in addition to the subsection (b-25)
10limitations governing the counting of the other fuel savings
11resulting from efficiency measures and programs.
12    As part of the annual informational filing to the
13Commission that is required under paragraph (9) of subsection
14(g) of this Section, each utility shall identify the specific
15electrification measures offered under this subsection (b-27);
16the quantity of each electrification measure that was
17installed by its customers; the average total cost, average
18utility cost, average reduction in fossil fuel consumption,
19and average increase in electricity consumption associated
20with each electrification measure; the portion of
21installations of each electrification measure that were in
22low-income single-family housing, low-income multifamily
23housing, non-low-income single-family housing, non-low-income
24multifamily housing, commercial buildings, and industrial
25facilities; and the quantity of savings associated with each
26measure category in each customer category that are being

 

 

SB3637- 79 -LRB103 38841 CES 68978 b

1counted toward the utility's applicable annual total savings
2requirement or the utility's incremental annual savings as
3defined in subsection (b-16). Prior to installing an
4electrification measure, the utility shall provide a customer
5with an estimate of the impact of the new measure on the
6customer's average monthly electric bill and total annual
7energy expenses.
8    (c) Electric utilities shall be responsible for overseeing
9the design, development, and filing of energy efficiency plans
10with the Commission and may, as part of that implementation,
11outsource various aspects of program development and
12implementation. A minimum of 10%, for electric utilities that
13serve more than 3,000,000 retail customers in the State, and a
14minimum of 7%, for electric utilities that serve less than
153,000,000 retail customers but more than 500,000 retail
16customers in the State, of the utility's entire portfolio
17funding level for a given year shall be used to procure
18cost-effective energy efficiency measures from units of local
19government, municipal corporations, school districts, public
20housing, and community college districts, provided that a
21minimum percentage of available funds shall be used to procure
22energy efficiency from public housing, which percentage shall
23be equal to public housing's share of public building energy
24consumption.
25    The utilities shall also implement energy efficiency
26measures targeted at low-income households, which, for

 

 

SB3637- 80 -LRB103 38841 CES 68978 b

1purposes of this Section, shall be defined as households at or
2below 80% of area median income, and expenditures to implement
3the measures shall be no less than $1,000,000 $40,000,000 per
4year for electric utilities that serve more than 3,000,000
5retail customers in the State and no less than $30,000
6$13,000,000 per year for electric utilities that serve less
7than 3,000,000 retail customers but more than 500,000 retail
8customers in the State. The ratio of spending on efficiency
9programs targeted at low-income multifamily buildings to
10spending on efficiency programs targeted at low-income
11single-family buildings shall be designed to achieve levels of
12savings from each building type that are approximately
13proportional to the magnitude of cost-effective lifetime
14savings potential in each building type. Investment in
15low-income whole-building weatherization programs shall
16constitute a minimum of 80% of a utility's total budget
17specifically dedicated to serving low-income customers.
18    The utilities shall work to bundle low-income energy
19efficiency offerings with other programs that serve low-income
20households to maximize the benefits going to these households.
21The utilities shall market and implement low-income energy
22efficiency programs in coordination with low-income assistance
23programs, the Illinois Solar for All Program, and
24weatherization whenever practicable. The program implementer
25shall walk the customer through the enrollment process for any
26programs for which the customer is eligible. The utilities

 

 

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1shall also pilot targeting customers with high arrearages,
2high energy intensity (ratio of energy usage divided by home
3or unit square footage), or energy assistance programs with
4energy efficiency offerings, and then track reduction in
5arrearages as a result of the targeting. This targeting and
6bundling of low-income energy programs shall be offered to
7both low-income single-family and multifamily customers
8(owners and residents).
9    The utilities shall invest in health and safety measures
10appropriate and necessary for comprehensively weatherizing a
11home or multifamily building, and shall implement a health and
12safety fund of at least 15% of the total income-qualified
13weatherization budget that shall be used for the purpose of
14making grants for technical assistance, construction,
15reconstruction, improvement, or repair of buildings to
16facilitate their participation in the energy efficiency
17programs targeted at low-income single-family and multifamily
18households. These funds may also be used for the purpose of
19making grants for technical assistance, construction,
20reconstruction, improvement, or repair of the following
21buildings to facilitate their participation in the energy
22efficiency programs created by this Section: (1) buildings
23that are owned or operated by registered 501(c)(3) public
24charities; and (2) day care centers, day care homes, or group
25day care homes, as defined under 89 Ill. Adm. Code Part 406,
26407, or 408, respectively.

 

 

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1    Each electric utility shall assess opportunities to
2implement cost-effective energy efficiency measures and
3programs through a public housing authority or authorities
4located in its service territory. If such opportunities are
5identified, the utility shall propose such measures and
6programs to address the opportunities. Expenditures to address
7such opportunities shall be credited toward the minimum
8procurement and expenditure requirements set forth in this
9subsection (c).
10    Implementation of energy efficiency measures and programs
11targeted at low-income households should be contracted, when
12it is practicable, to independent third parties that have
13demonstrated capabilities to serve such households, with a
14preference for not-for-profit entities and government agencies
15that have existing relationships with or experience serving
16low-income communities in the State.
17    Each electric utility shall develop and implement
18reporting procedures that address and assist in determining
19the amount of energy savings that can be applied to the
20low-income procurement and expenditure requirements set forth
21in this subsection (c). Each electric utility shall also track
22the types and quantities or volumes of insulation and air
23sealing materials, and their associated energy saving
24benefits, installed in energy efficiency programs targeted at
25low-income single-family and multifamily households.
26    The electric utilities shall participate in a low-income

 

 

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1energy efficiency accountability committee ("the committee"),
2which will directly inform the design, implementation, and
3evaluation of the low-income and public-housing energy
4efficiency programs. The committee shall be comprised of the
5electric utilities subject to the requirements of this
6Section, the gas utilities subject to the requirements of
7Section 8-104 of this Act, the utilities' low-income energy
8efficiency implementation contractors, nonprofit
9organizations, community action agencies, advocacy groups,
10State and local governmental agencies, public-housing
11organizations, and representatives of community-based
12organizations, especially those living in or working with
13environmental justice communities and BIPOC communities. The
14committee shall be composed of 2 geographically differentiated
15subcommittees: one for stakeholders in northern Illinois and
16one for stakeholders in central and southern Illinois. The
17subcommittees shall meet together at least twice per year.
18    There shall be one statewide leadership committee led by
19and composed of community-based organizations that are
20representative of BIPOC and environmental justice communities
21and that includes equitable representation from BIPOC
22communities. The leadership committee shall be composed of an
23equal number of representatives from the 2 subcommittees. The
24subcommittees shall address specific programs and issues, with
25the leadership committee convening targeted workgroups as
26needed. The leadership committee may elect to work with an

 

 

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1independent facilitator to solicit and organize feedback,
2recommendations and meeting participation from a wide variety
3of community-based stakeholders. If a facilitator is used,
4they shall be fair and responsive to the needs of all
5stakeholders involved in the committee.
6     All committee meetings must be accessible, with rotating
7locations if meetings are held in-person, virtual
8participation options, and materials and agendas circulated in
9advance.
10    There shall also be opportunities for direct input by
11committee members outside of committee meetings, such as via
12individual meetings, surveys, emails and calls, to ensure
13robust participation by stakeholders with limited capacity and
14ability to attend committee meetings. Committee meetings shall
15emphasize opportunities to bundle and coordinate delivery of
16low-income energy efficiency with other programs that serve
17low-income communities, such as the Illinois Solar for All
18Program and bill payment assistance programs. Meetings shall
19include educational opportunities for stakeholders to learn
20more about these additional offerings, and the committee shall
21assist in figuring out the best methods for coordinated
22delivery and implementation of offerings when serving
23low-income communities. The committee shall directly and
24equitably influence and inform utility low-income and
25public-housing energy efficiency programs and priorities.
26Participating utilities shall implement recommendations from

 

 

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1the committee whenever possible.
2    Participating utilities shall track and report how input
3from the committee has led to new approaches and changes in
4their energy efficiency portfolios. This reporting shall occur
5at committee meetings and in quarterly energy efficiency
6reports to the Stakeholder Advisory Group and Illinois
7Commerce Commission, and other relevant reporting mechanisms.
8Participating utilities shall also report on relevant equity
9data and metrics requested by the committee, such as energy
10burden data, geographic, racial, and other relevant
11demographic data on where programs are being delivered and
12what populations programs are serving.
13    The Illinois Commerce Commission shall oversee and have
14relevant staff participate in the committee. The committee
15shall have a budget of 0.25% of each utility's entire
16efficiency portfolio funding for a given year. The budget
17shall be overseen by the Commission. The budget shall be used
18to provide grants for community-based organizations serving on
19the leadership committee, stipends for community-based
20organizations participating in the committee, grants for
21community-based organizations to do energy efficiency outreach
22and education, and relevant meeting needs as determined by the
23leadership committee. The education and outreach shall
24include, but is not limited to, basic energy efficiency
25education, information about low-income energy efficiency
26programs, and information on the committee's purpose,

 

 

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1structure, and activities.
2    (d) Notwithstanding any other provision of law to the
3contrary, a utility providing approved energy efficiency
4measures and, if applicable, demand-response measures in the
5State shall be permitted to recover all reasonable and
6prudently incurred costs of those measures from all retail
7customers, except as provided in subsection (l) of this
8Section, 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
24Public Act 99-906), a utility subject to the requirements of
25this Section may elect to defer, as a regulatory asset, up to
26the full amount of its expenditures incurred under this

 

 

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1Section for each annual period, including, but not limited to,
2any expenditures incurred above the funding level set by
3subsection (f) of this Section for a given year. The total
4expenditures deferred as a regulatory asset in a given year
5shall be amortized and recovered over a period that is equal to
6the weighted average of the energy efficiency measure lives
7implemented for that year that are reflected in the regulatory
8asset. The unamortized balance shall be recognized as of
9December 31 for a given year. The utility shall also earn a
10return on the total of the unamortized balances of all of the
11energy efficiency regulatory assets, less any deferred taxes
12related to those unamortized balances, at an annual rate equal
13to the utility's weighted average cost of capital that
14includes, based on a year-end capital structure, the utility's
15actual cost of debt for the applicable calendar year and a cost
16of equity, which shall be calculated as the sum of the (i) the
17average for the applicable calendar year of the monthly
18average yields of 30-year U.S. Treasury bonds published by the
19Board of Governors of the Federal Reserve System in its weekly
20H.15 Statistical Release or successor publication; and (ii)
21580 basis points, including a revenue conversion factor
22calculated to recover or refund all additional income taxes
23that may be payable or receivable as a result of that return.
24Capital investment costs shall be depreciated and recovered
25over their useful lives consistent with generally accepted
26accounting principles. The weighted average cost of capital

 

 

SB3637- 99 -LRB103 38841 CES 68978 b

1shall be applied to the capital investment cost balance, less
2any accumulated depreciation and accumulated deferred income
3taxes, as of December 31 for a given year.
4    When an electric utility creates a regulatory asset under
5the provisions of this Section, the costs are recovered over a
6period during which customers also receive a benefit which is
7in the public interest. Accordingly, it is the intent of the
8General Assembly that an electric utility that elects to
9create a regulatory asset under the provisions of this Section
10shall recover all of the associated costs as set forth in this
11Section. After the Commission has approved the prudence and
12reasonableness of the costs that comprise the regulatory
13asset, the electric utility shall be permitted to recover all
14such costs, and the value and recoverability through rates of
15the associated regulatory asset shall not be limited, altered,
16impaired, or reduced.
17    (f) Beginning in 2017, each electric utility shall file an
18energy efficiency plan with the Commission to meet the energy
19efficiency standards for the next applicable multi-year period
20beginning January 1 of the year following the filing,
21according to the schedule set forth in paragraphs (1) through
22(3) of this subsection (f). If a utility does not file such a
23plan on or before the applicable filing deadline for the plan,
24it shall face a penalty of $100,000 per day until the plan is
25filed.
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
13proposals to meet the energy efficiency standards identified
14in subsection (b-5), or (b-15), or (b-16) as applicable and as
15such standards may have been modified under this subsection
16(f), taking into account the unique circumstances of the
17utility's service territory. For those plans commencing on
18January 1, 2018, the Commission shall seek public comment on
19the utility's plan and shall issue an order approving or
20disapproving each plan no later than 105 days after June 1,
212017 (the effective date of Public Act 99-906). For those
22plans commencing after December 31, 2021, the Commission shall
23seek public comment on the utility's plan and shall issue an
24order approving or disapproving each plan within 6 months
25after its submission. If the Commission disapproves a plan,
26the Commission shall, within 30 days, describe in detail the

 

 

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1reasons for the disapproval and describe a path by which the
2utility may file a revised draft of the plan to address the
3Commission's concerns satisfactorily. If the utility does not
4refile with the Commission within 60 days, the utility shall
5be subject to penalties at a rate of $100,000 per day until the
6plan is filed. This process shall continue, and penalties
7shall accrue, until the utility has successfully filed a
8portfolio of energy efficiency and demand-response measures.
9Penalties shall be deposited into the Energy Efficiency Trust
10Fund.
11    (g) In submitting proposed plans and funding levels under
12subsection (f) of this Section to meet the savings goals
13identified in subsection (b-5), or (b-15), or (b-16) of this
14Section, 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

 

 

SB3637- 109 -LRB103 38841 CES 68978 b

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

 

 

SB3637- 110 -LRB103 38841 CES 68978 b

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

 

 

SB3637- 113 -LRB103 38841 CES 68978 b

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

 

 

SB3637- 114 -LRB103 38841 CES 68978 b

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

 

 

SB3637- 115 -LRB103 38841 CES 68978 b

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,

 

 

SB3637- 116 -LRB103 38841 CES 68978 b

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:

 

 

SB3637- 117 -LRB103 38841 CES 68978 b

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

 

 

SB3637- 118 -LRB103 38841 CES 68978 b

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

 

 

SB3637- 119 -LRB103 38841 CES 68978 b

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
2demand-response program revenue may be allocated for research,
3development, or pilot deployment of new equipment or measures.
4Electric utilities shall work with interested stakeholders to
5formulate a plan for how these funds should be spent,
6incorporate statewide approaches for these allocations, and
7file a 4-year plan that demonstrates that collaboration. If a
8utility files a request for modified annual energy savings
9goals with the Commission, then a utility shall forgo spending
10portfolio dollars on research and development proposals.
11    (i) When practicable, electric utilities shall incorporate
12advanced metering infrastructure data into the planning,
13implementation, and evaluation of energy efficiency measures
14and programs, subject to the data privacy and confidentiality
15protections of applicable law.
16    (j) The independent evaluator shall follow the guidelines
17and use the savings set forth in Commission-approved energy
18efficiency policy manuals and technical reference manuals, as
19each may be updated from time to time. Until such time as
20measure life values for energy efficiency measures implemented
21for low-income households under subsection (c) of this Section
22are incorporated into such Commission-approved manuals, the
23low-income measures shall have the same measure life values
24that are established for same measures implemented in
25households that are not low-income households.
26    (k) Notwithstanding any provision of law to the contrary,

 

 

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1an electric utility subject to the requirements of this
2Section may file a tariff cancelling an automatic adjustment
3clause tariff in effect under this Section or Section 8-103,
4which shall take effect no later than one business day after
5the date such tariff is filed. Thereafter, the utility shall
6be authorized to defer and recover its expenditures incurred
7under this Section through a new tariff authorized under
8subsection (d) of this Section or in the utility's next rate
9case under Article IX or Section 16-108.5 of this Act, with
10interest at an annual rate equal to the utility's weighted
11average cost of capital as approved by the Commission in such
12case. If the utility elects to file a new tariff under
13subsection (d) of this Section, the utility may file the
14tariff within 10 days after June 1, 2017 (the effective date of
15Public Act 99-906), and the cost inputs to such tariff shall be
16based on the projected costs to be incurred by the utility
17during the calendar year in which the new tariff is filed and
18that were not recovered under the tariff that was cancelled as
19provided for in this subsection. Such costs shall include
20those incurred or to be incurred by the utility under its
21multi-year plan approved under subsections (f) and (g) of this
22Section, including, but not limited to, projected capital
23investment costs and projected regulatory asset balances with
24correspondingly updated depreciation and amortization reserves
25and expense. The Commission shall, after notice and hearing,
26approve, or approve with modification, such tariff and cost

 

 

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1inputs no later than 75 days after the utility filed the
2tariff, provided that such approval, or approval with
3modification, shall be consistent with the provisions of this
4Section to the extent they do not conflict with this
5subsection (k). The tariff approved by the Commission shall
6take effect no later than 5 days after the Commission enters
7its order approving the tariff.
8    No later than 60 days after the effective date of the
9tariff cancelling the utility's automatic adjustment clause
10tariff, the utility shall file a reconciliation that
11reconciles the moneys collected under its automatic adjustment
12clause tariff with the costs incurred during the period
13beginning June 1, 2016 and ending on the date that the electric
14utility's automatic adjustment clause tariff was cancelled. In
15the event the reconciliation reflects an under-collection, the
16utility shall recover the costs as specified in this
17subsection (k). If the reconciliation reflects an
18over-collection, the utility shall apply the amount of such
19over-collection as a one-time credit to retail customers'
20bills.
21    (l) (Blank). For the calendar years covered by a
22multi-year plan commencing after December 31, 2017,
23subsections (a) through (j) of this Section do not apply to
24eligible large private energy customers that have chosen to
25opt 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
17part of a proceeding to approve a multi-year plan under
18subsections (f) and (g) of this Section if the multi-year plan
19has been designed to maximize savings, but does not meet the
20cost cap limitations of this Section, the Commission shall
21reduce the amount of energy efficiency measures implemented
22for any single year, and whose costs are recovered under
23subsection (d) of this Section, by an amount necessary to
24limit the estimated average net increase due to the cost of the
25measures 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,
10of the average amount paid per kilowatthour by residential
11eligible retail customers during calendar year 2015. An
12electric utility may plan to spend up to 10% more in any year
13during an applicable multi-year plan period to
14cost-effectively achieve additional savings so long as the
15average over the applicable multi-year plan period does not
16exceed the percentages defined in items (1) through (5). To
17determine the total amount that may be spent by an electric
18utility in any single year, the applicable percentage of the
19average amount paid per kilowatthour shall be multiplied by
20the total amount of energy delivered by such electric utility
21in the calendar year 2015, adjusted to reflect the proportion
22of the utility's load attributable to customers that have
23opted out of subsections (a) through (j) of this Section under
24subsection (l) of this Section. For purposes of this
25subsection (m), the amount paid per kilowatthour includes,
26without limitation, estimated amounts paid for supply,

 

 

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1transmission, distribution, surcharges, and add-on taxes. For
2purposes of this Section, "eligible retail customers" shall
3have the meaning set forth in Section 16-111.5 of this Act.
4Once the Commission has approved a plan under subsections (f)
5and (g) of this Section, no subsequent rate impact
6determinations shall be made.
7    (n) A utility shall take advantage of the efficiencies
8available through existing Illinois Home Weatherization
9Assistance Program infrastructure and services, such as
10enrollment, marketing, quality assurance and implementation,
11which can reduce the need for similar services at a lower cost
12than utility-only programs, subject to capacity constraints at
13community action agencies, for both single-family and
14multifamily weatherization services, to the extent Illinois
15Home Weatherization Assistance Program community action
16agencies provide multifamily services. A utility's plan shall
17demonstrate that in formulating annual weatherization budgets,
18it has sought input and coordination with community action
19agencies regarding agencies' capacity to expand and maximize
20Illinois Home Weatherization Assistance Program delivery using
21the 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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1to provide net electricity metering, as defined in this
2Section, for eligible customers can encourage private
3investment in renewable energy resources, stimulate economic
4growth, enhance the continued diversification of Illinois'
5energy resource mix, and protect the Illinois environment.
6Further, to achieve the goals of this Act that robust options
7for customer-site distributed generation continue to thrive in
8Illinois, the General Assembly finds that a predictable
9transition must be ensured for customers between full net
10metering at the retail electricity rate to the distribution
11generation rebate described in Section 16-107.6.
12    (b) As used in this Section, (i) "community renewable
13generation project" shall have the meaning set forth in
14Section 1-10 of the Illinois Power Agency Act; (ii) "eligible
15customer" means a retail customer that owns, hosts, or
16operates, including any third-party owned systems, a solar,
17wind, or other eligible renewable electrical generating
18facility that is located on the customer's premises or
19customer's side of the billing meter and is intended primarily
20to offset the customer's own current or future electrical
21requirements; (iii) "electricity provider" means an electric
22utility or alternative retail electric supplier; (iv)
23"eligible renewable electrical generating facility" means a
24generator, which may include the co-location of an energy
25storage system, that is interconnected under rules adopted by
26the Commission and is powered by solar electric energy, wind,

 

 

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1dedicated crops grown for electricity generation, agricultural
2residues, untreated and unadulterated wood waste, livestock
3manure, anaerobic digestion of livestock or food processing
4waste, fuel cells or microturbines powered by renewable fuels,
5or hydroelectric energy; (v) "net electricity metering" (or
6"net metering") means the measurement, during the billing
7period applicable to an eligible customer, of the net amount
8of electricity supplied by an electricity provider to the
9customer or provided to the electricity provider by the
10customer or subscriber; (vi) "subscriber" shall have the
11meaning as set forth in Section 1-10 of the Illinois Power
12Agency Act; (vii) "subscription" shall have the meaning set
13forth in Section 1-10 of the Illinois Power Agency Act; (viii)
14"energy storage system" means commercially available
15technology that is capable of absorbing energy and storing it
16for a period of time for use at a later time, including, but
17not limited to, electrochemical, thermal, and
18electromechanical technologies, and may be interconnected
19behind the customer's meter or interconnected behind its own
20meter; and (ix) "future electrical requirements" means modeled
21electrical requirements upon occupation of a new or vacant
22property, and other reasonable expectations of future
23electrical use, as well as, for occupied properties, a
24reasonable approximation of the annual load of 2 electric
25vehicles and, for non-electric heating customers, a reasonable
26approximation of the incremental electric load associated with

 

 

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1fuel switching. The approximations shall be applied to the
2appropriate net metering tariff and do not need to be unique to
3each individual eligible customer. The utility shall submit
4these approximations to the Commission for review,
5modification, and approval; and (x) "electricity provider" and
6"electric utility" includes municipalities and municipal power
7agencies as defined in Section 11-119.3-1 of the Illinois
8Municipal Code and electric cooperatives as defined in Section
93-119 of this Act.
10    (c) A net metering facility shall be equipped with
11metering equipment that can measure the flow of electricity in
12both 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.

 

 

SB3637- 139 -LRB103 38841 CES 68978 b

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
4credit for the net electricity supplied to eligible customers
5or provided by eligible customers whose electric service has
6not been declared competitive pursuant to Section 16-113 of
7this Act as of July 1, 2011 and whose electric delivery service
8is provided and measured on a kilowatt-hour basis and electric
9supply service is not provided based on hourly pricing in the
10following 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
11credit for the net electricity supplied to eligible customers
12or provided by eligible customers whose electric service has
13not been declared competitive pursuant to Section 16-113 of
14this Act as of July 1, 2011 and whose electric delivery service
15is provided and measured on a kilowatt-hour basis and electric
16supply service is provided based on hourly pricing or
17time-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
16credit for the net electricity supplied to eligible customers
17whose electric service has not been declared competitive
18pursuant to Section 16-113 of this Act as of July 1, 2011 and
19whose electric delivery service is provided and measured on a
20kilowatt demand basis and electric supply service is not
21provided 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
26service to eligible customers who utilize net metering at

 

 

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1non-discriminatory rates that are identical, with respect to
2rate structure, retail rate components, and any monthly
3charges, to the rates that the customer would be charged if not
4a net metering customer. An electricity provider shall not
5charge net metering customers any fee or charge or require
6additional equipment, insurance, or any other requirements not
7specifically authorized by interconnection standards
8authorized by the Commission, unless the fee, charge, or other
9requirement would apply to other similarly situated customers
10who are not net metering customers. The customer will remain
11responsible for all taxes, fees, and utility delivery charges
12that would otherwise be applicable to the net amount of
13electricity used by the customer. Subsections (c) through (e)
14of this Section shall not be construed to prevent an
15arms-length agreement between an electricity provider and an
16eligible customer that sets forth different prices, terms, and
17conditions for the provision of net metering service,
18including, but not limited to, the provision of the
19appropriate metering equipment for non-residential customers.
20    (f) Notwithstanding the requirements of subsections (c)
21through (e-5) of this Section, an electricity provider must
22require dual-channel metering for customers operating eligible
23renewable electrical generating facilities to whom the
24provisions of neither subsection (d), (d-5), nor (e) of this
25Section apply. In such cases, electricity charges and credits
26shall 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
2renewable energy credits or greenhouse gas credits, the
3eligible customer shall be treated as owning and having title
4to the renewable energy attributes, renewable energy credits,
5and greenhouse gas emission credits related to any electricity
6produced by the qualified generating unit. The electricity
7provider may not condition participation in a net metering
8program on the signing over of a customer's renewable energy
9credits; provided, however, this subsection (g) shall not be
10construed to prevent an arms-length agreement between an
11electricity provider and an eligible customer that sets forth
12the ownership or title of the credits.
13    (h) Within 120 days after the effective date of this
14amendatory Act of the 95th General Assembly, the Commission
15shall establish standards for net metering and, if the
16Commission has not already acted on its own initiative,
17standards for the interconnection of eligible renewable
18generating equipment to the utility system. The
19interconnection standards shall address any procedural
20barriers, delays, and administrative costs associated with the
21interconnection of customer-generation while ensuring the
22safety and reliability of the units and the electric utility
23system. The Commission shall consider the Institute of
24Electrical and Electronics Engineers (IEEE) Standard 1547 and
25the issues of (i) reasonable and fair fees and costs, (ii)
26clear timelines for major milestones in the interconnection

 

 

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1process, (iii) nondiscriminatory terms of agreement, and (iv)
2any best practices for interconnection of distributed
3generation.
4    (h-5) Within 90 days after the effective date of this
5amendatory Act of the 102nd General Assembly, the Commission
6shall:
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
17metering no later than April 1, 2008.
18    (j) An electricity provider shall provide net metering to
19eligible customers according to subsections (d), (d-5), and
20(e). Eligible renewable electrical generating facilities for
21which eligible customers registered for net metering before
22January 1, 2025 shall continue to receive net metering
23services according to subsections (d), (d-5), and (e) of this
24Section for the lifetime of the system, regardless of whether
25those retail customers change electricity providers or whether
26the retail customer benefiting from the system changes. On and

 

 

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1after January 1, 2025, any eligible customer that applies for
2net metering and previously would have qualified under
3subsections (d), (d-5), or (e) shall only be eligible for net
4metering as described in subsection (n).
5    (k) Each electricity provider shall maintain records and
6report annually to the Commission the total number of net
7metering customers served by the provider, as well as the
8type, capacity, and energy sources of the generating systems
9used by the net metering customers. Nothing in this Section
10shall limit the ability of an electricity provider to request
11the redaction of information deemed by the Commission to be
12confidential business information.
13    (l)(1) Notwithstanding the definition of "eligible
14customer" in item (ii) of subsection (b) of this Section, each
15electricity provider shall allow net metering as set forth in
16this subsection (l) and for the following projects, provided
17that only electric utilities serving more than 200,000
18customers as of January 1, 2021 shall provide net metering for
19projects that are eligible for subparagraph (C) of this
20paragraph (1) and have energized after the effective date of
21this 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
17renewable electric generating facility that serves the demand
18of the properties, units, or apartments identified in
19paragraphs (1) and (2) of this subsection (l) shall not exceed
205,000 kilowatts in nameplate capacity in total. Any eligible
21renewable electrical generating facility or community
22renewable generation project that is powered by photovoltaic
23electric energy and installed after the effective date of this
24amendatory Act of the 99th General Assembly must be installed
25by a qualified person in compliance with the requirements of
26Section 16-128A of the Public Utilities Act and any rules or

 

 

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1regulations adopted thereunder.
2    (2) Notwithstanding anything to the contrary, an
3electricity provider shall provide credits for the electricity
4produced by the projects described in paragraph (1) of this
5subsection (l). The electricity provider shall provide credits
6that include at least energy supply, capacity, transmission,
7and, if applicable, the purchased energy adjustment on the
8subscriber's monthly bill equal to the subscriber's share of
9the production of electricity from the project, as determined
10by paragraph (3) of this subsection (l). For customers with
11transmission or capacity charges not charged on a
12kilowatt-hour basis, the electricity provider shall prepare a
13reasonable approximation of the kilowatt-hour equivalent value
14and provide that value as a monetary credit. The electricity
15provider shall submit these approximation methodologies to the
16Commission for review, modification, and approval.
17Notwithstanding anything to the contrary, customers on payment
18plans or participating in budget billing programs shall have
19credits applied on a monthly basis.
20    (3) Notwithstanding anything to the contrary and
21regardless of whether a subscriber to an eligible community
22renewable generation project receives power and energy service
23from the electric utility or an alternative retail electric
24supplier, for projects eligible under paragraph (C) of
25subparagraph (1) of this subsection (l), electric utilities
26serving more than 200,000 customers as of January 1, 2021

 

 

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1shall provide the monetary credits to a subscriber's
2subsequent bill for the electricity produced by community
3renewable generation projects. The electric utility shall
4provide monetary credits to a subscriber's subsequent bill at
5the utility's total price to compare equal to the subscriber's
6share of the production of electricity from the project, as
7determined by paragraph (5) of this subsection (l). For the
8purposes of this subsection, "total price to compare" means
9the rate or rates published by the Illinois Commerce
10Commission for energy supply for eligible customers receiving
11supply service from the electric utility, and shall include
12energy, capacity, transmission, and the purchased energy
13adjustment. Notwithstanding anything to the contrary,
14customers on payment plans or participating in budget billing
15programs shall have credits applied on a monthly basis. Any
16applicable credit or reduction in load obligation from the
17production of the community renewable generating projects
18receiving a credit under this subsection shall be credited to
19the electric utility to offset the cost of providing the
20credit. To the extent that the credit or load obligation
21reduction does not completely offset the cost of providing the
22credit to subscribers of community renewable generation
23projects as described in this subsection, the electric utility
24may recover the remaining costs through its Multi-Year Rate
25Plan. All electric utilities serving 200,000 or fewer
26customers as of January 1, 2021 shall only provide the

 

 

SB3637- 154 -LRB103 38841 CES 68978 b

1monetary credits to a subscriber's subsequent bill for the
2electricity produced by community renewable generation
3projects if the subscriber receives power and energy service
4from the electric utility. Alternative retail electric
5suppliers providing power and energy service to a subscriber
6located within the service territory of an electric utility
7not subject to Sections 16-108.18 and 16-118 shall provide the
8monetary credits to the subscriber's subsequent bill for the
9electricity produced by community renewable generation
10projects.
11    (4) If requested by the owner or operator of a community
12renewable generating project, an electric utility serving more
13than 200,000 customers as of January 1, 2021 shall enter into a
14net crediting agreement with the owner or operator to include
15a subscriber's subscription fee on the subscriber's monthly
16electric bill and provide the subscriber with a net credit
17equivalent to the total bill credit value for that generation
18period minus the subscription fee, provided the subscription
19fee is structured as a fixed percentage of bill credit value.
20The net crediting agreement shall set forth payment terms from
21the electric utility to the owner or operator of the community
22renewable generating project, and the electric utility may
23charge a net crediting fee to the owner or operator of a
24community renewable generating project that may not exceed 2%
25of the bill credit value. Notwithstanding anything to the
26contrary, an electric utility serving 200,000 customers or

 

 

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1fewer as of January 1, 2021 shall not be obligated to enter
2into a net crediting agreement with the owner or operator of a
3community renewable generating project.
4    (5) For the purposes of facilitating net metering, the
5owner or operator of the eligible renewable electrical
6generating facility or community renewable generation project
7shall be responsible for determining the amount of the credit
8that each customer or subscriber participating in a project
9under this subsection (l) is to receive in the following
10manner:
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
6amendatory Act of the 102nd General Assembly, each electric
7utility subject to this Section shall file a tariff or tariffs
8to implement the provisions of subsection (l) of this Section,
9which shall, consistent with the provisions of subsection (l),
10describe the terms and conditions under which owners or
11operators of qualifying properties, units, or apartments may
12participate in net metering. The Commission shall approve, or
13approve with modification, the tariff within 120 days after
14the effective date of this amendatory Act of the 102nd General
15Assembly.
16    (m) Nothing in this Section shall affect the right of an
17electricity provider to continue to provide, or the right of a
18retail customer to continue to receive service pursuant to a
19contract for electric service between the electricity provider
20and the retail customer in accordance with the prices, terms,
21and conditions provided for in that contract. Either the
22electricity provider or the customer may require compliance
23with the prices, terms, and conditions of the contract.
24    (n) On and after January 1, 2025, the net metering
25services described in subsections (d), (d-5), and (e) of this
26Section shall no longer be offered, except as to those

 

 

SB3637- 158 -LRB103 38841 CES 68978 b

1eligible renewable electrical generating facilities for which
2retail customers are receiving net metering service under
3these subsections at the time the net metering services under
4those subsections are no longer offered; those systems shall
5continue to receive net metering services described in
6subsections (d), (d-5), and (e) of this Section for the
7lifetime of the system, regardless of if those retail
8customers change electricity providers or whether the retail
9customer benefiting from the system changes. The electric
10utility serving more than 200,000 customers as of January 1,
112021 is responsible for ensuring the billing credits continue
12without lapse for the lifetime of systems, as required in
13subsection (o). Those retail customers that begin taking net
14metering service after the date that net metering services are
15no longer offered under such subsections shall be subject to
16the provisions set forth in the following paragraphs (1)
17through (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
22amendatory Act of the 102nd General Assembly, each electric
23utility subject to this Section shall file a tariff, which
24shall, consistent with the provisions of this Section, propose
25the terms and conditions under which a customer may
26participate in net metering. The tariff for electric utilities

 

 

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1serving more than 200,000 customers as of January 1, 2021
2shall also provide a streamlined and transparent bill
3crediting system for net metering to be managed by the
4electric utilities. The terms and conditions shall include,
5but are not limited to, that an electric utility shall manage
6and maintain billing of net metering credits and charges
7regardless of if the eligible customer takes net metering
8under an electric utility or alternative retail electric
9supplier. The electric utility serving more than 200,000
10customers as of January 1, 2021 shall process and approve all
11net metering applications, even if an eligible customer is
12served by an alternative retail electric supplier; and the
13utility shall forward application approval to the appropriate
14alternative retail electric supplier. Eligibility for net
15metering shall remain with the owner of the utility billing
16address such that, if an eligible renewable electrical
17generating facility changes ownership, the net metering
18eligibility transfers to the new owner. The electric utility
19serving more than 200,000 customers as of January 1, 2021
20shall manage net metering billing for eligible customers to
21ensure full crediting occurs on electricity bills, including,
22but not limited to, ensuring net metering crediting begins
23upon commercial operation date, net metering billing transfers
24immediately if an eligible customer switches from an electric
25utility to alternative retail electric supplier or vice versa,
26and net metering billing transfers between ownership of a

 

 

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1valid billing address. All transfers referenced in the
2preceding sentence shall include transfer of all banked
3credits. All electric utilities serving 200,000 or fewer
4customers as of January 1, 2021 shall manage net metering
5billing for eligible customers receiving power and energy
6service from the electric utility to ensure full crediting
7occurs on electricity bills, ensuring net metering crediting
8begins upon commercial operation date, net metering billing
9transfers immediately if an eligible customer switches from an
10electric utility to alternative retail electric supplier or
11vice versa, and net metering billing transfers between
12ownership of a valid billing address. Alternative retail
13electric suppliers providing power and energy service to
14eligible customers located within the service territory of an
15electric utility serving 200,000 or fewer customers as of
16January 1, 2021 shall manage net metering billing for eligible
17customers to ensure full crediting occurs on electricity
18bills, including, but not limited to, ensuring net metering
19crediting begins upon commercial operation date, net metering
20billing transfers immediately if an eligible customer switches
21from an electric utility to alternative retail electric
22supplier or vice versa, and net metering billing transfers
23between 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
3pricing plans can lower energy costs for consumers and reduce
4grid costs as well as help the State achieve its energy policy
5goals by improving load shape, encouraging energy
6conservation, and shifting usage away from periods where
7fossil fuels are used to meet peak demand. Further, by
8providing consumers information relating the costs of service
9to the time of energy usage, time-of-use rates can help
10consumers reduce their energy bills by using electricity when
11it is less costly. Time-of-use rates can help allocate
12electricity system costs more accurately and thus equitably to
13those who cause costs. Such rates can reduce the need for
14ramping resources and increase the grid's ability to
15cost-effectively integrate greater quantities of variable
16renewable energy and distributed energy resources.
17    (b) An electric utility that has a tariff approved under
18subsection (d) of Section 16-108.18 within one year of this
19amendatory Act of the 103rd General Assembly shall also offer
20at least one market-based, residential rate for eligible
21retail customers that choose to take power and energy supply
22service from the utility. If the utility has a pending request
23for approval of a Multi-Year Integrated Grid Plan, the utility
24shall update its filing in that docket to reflect the likely
25impacts of the time-of-use rate offering. The utility shall
26file its time-of-use rate tariff no later than 120 days after

 

 

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1the effective date of this amendatory Act of the 103rd General
2Assembly, and each utility subject to this requirement shall
3implement the requirements of this subsection by filing a
4tariff with the Commission. The tariff or tariffs shall be
5subject 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
19customers" includes, but is not limited to, customers
20participating in net electricity metering under the terms of
21Section 16-107.5.
22    (c) The Commission shall, after notice and hearing,
23approve the tariff or tariffs with modifications the
24Commission finds necessary to improve the program design,
25customer participation in the program, or coordination with
26existing utility pricing programs, energy efficiency programs,

 

 

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1demand-response programs, and any other programs supporting
2State energy policy goals and the integration of distributed
3energy resources. The Commission shall also consider how the
4proposed time-of-use rate design reflects the system costs and
5usage patterns of the utility. A proceeding under this
6subsection may not exceed 120 days in length.
7    (d) If the Commission issues an order pursuant to this
8subsection, the affected electric utility shall contract with
9an entity not affiliated with the electric utility to serve as
10a program administrator to develop and implement a program to
11provide consumer outreach, enrollment, and education
12concerning time-of-use pricing and to establish and administer
13an information system and technical and other customer
14assistance that is necessary to enable customers to manage
15electricity use. The program administrator: (i) shall be
16selected and compensated by the electric utility, subject to
17Commission approval; (ii) shall have demonstrated technical
18and managerial competence in the development and
19administration of demand management programs; and (iii) may
20develop and implement risk management, energy efficiency, and
21other services related to energy use management for which the
22program administrator shall be compensated by participants in
23the program receiving such services. The electric utility
24shall provide the program administrator with all information
25and assistance necessary to perform the program
26administrator's duties, including, but not limited to,

 

 

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1customer, account, and energy use data. The electric utility
2shall permit the program administrator to include inserts in
3residential customer bills 2 times per year to assist with
4customer outreach and enrollment. The program administrator
5shall submit an annual report to the electric utility no later
6than April 1 of each year describing the operation and results
7of the program, including information concerning the number
8and types of customers using the program, changes in
9customers' energy use patterns, an assessment of the value of
10the program to both participants and nonparticipants, and
11recommendations concerning modification of the program and the
12tariff or tariffs filed under this Section. This report shall
13be filed by the electric utility with the Commission within 30
14days after receipt and shall be available to the public on the
15Commission's website.
16    (e) Once the tariff or tariffs has been in effect for 12
17months, the Commission may, upon complaint, petition, or its
18own initiative, open a proceeding to investigate whether
19changes or modifications to the tariff or tariffs, program
20administration and any other program design element is
21necessary to achieve the goals described in subsection (a) and
22to shifting usage away from periods where fossil fuels are
23used to meet peak demand and realign usage to periods when
24renewable generation is available. Such a proceeding may not
25last more than 180 days from the date upon which the
26investigation is opened by Commission order. Thereafter, the

 

 

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1Commission may, upon complaint, petition, or its own
2initiative, open a proceeding to investigate changes or
3modifications to the tariff or tariffs at any time the
4Commission deems reasonable in order to achieve these
5objectives.
6    (f) An electric utility shall be entitled to recover
7reasonable costs incurred in complying with this Section, if
8the recovery of the costs is fairly apportioned among its
9residential customers.
10    (g) The electric utility's tariff or tariffs filed
11pursuant to this Section shall be subject to the provisions of
12Article IX of this Act insofar as they do not conflict with
13this Section.
14    (h) This Section does not apply to any electric utility
15providing 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
19at least 100,000 customers in Illinois shall procure power and
20energy for its eligible retail customers in accordance with
21the applicable provisions set forth in Section 1-75 of the
22Illinois Power Agency Act and this Section. Beginning with the
23delivery year commencing on June 1, 2017, such electric
24utility shall also procure zero emission credits from zero
25emission facilities in accordance with the applicable

 

 

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1provisions set forth in Section 1-75 of the Illinois Power
2Agency Act, and, for years beginning on or after June 1, 2017,
3the utility shall procure renewable energy resources in
4accordance with the applicable provisions set forth in Section
51-75 of the Illinois Power Agency Act and this Section.
6Beginning with the delivery year commencing on June 1, 2022,
7an electric utility serving over 3,000,000 customers shall
8also procure carbon mitigation credits from carbon-free energy
9resources in accordance with the applicable provisions set
10forth in Section 1-75 of the Illinois Power Agency Act and this
11Section. A small multi-jurisdictional electric utility that on
12December 31, 2005 served less than 100,000 customers in
13Illinois may elect to procure power and energy for all or a
14portion of its eligible Illinois retail customers in
15accordance with the applicable provisions set forth in this
16Section and Section 1-75 of the Illinois Power Agency Act.
17This Section shall not apply to a small multi-jurisdictional
18utility until such time as a small multi-jurisdictional
19utility requests the Illinois Power Agency to prepare a
20procurement plan for its eligible retail customers. "Eligible
21retail customers" for the purposes of this Section means those
22retail customers that purchase power and energy from the
23electric utility under fixed-price bundled service tariffs,
24other than those retail customers whose service is declared or
25deemed competitive under Section 16-113 and those other
26customer groups specified in this Section, including

 

 

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1self-generating customers, customers electing hourly pricing,
2or those customers who are otherwise ineligible for
3fixed-price bundled tariff service. For those customers that
4are excluded from the procurement plan's electric supply
5service requirements, and the utility shall procure any supply
6requirements, including capacity, ancillary services, and
7hourly priced energy, in the applicable markets as needed to
8serve those customers, provided that the utility may include
9in its procurement plan load requirements for the load that is
10associated with those retail customers whose service has been
11declared or deemed competitive pursuant to Section 16-113 of
12this Act to the extent that those customers are purchasing
13power and energy during one of the transition periods
14identified in subsection (b) of Section 16-113 of this Act.
15    (b) A procurement plan shall be prepared for each electric
16utility consistent with the applicable requirements of the
17Illinois Power Agency Act and this Section. For purposes of
18this Section, Illinois electric utilities that are affiliated
19by virtue of a common parent company are considered to be a
20single electric utility. Small multi-jurisdictional utilities
21may request a procurement plan for a portion of or all of its
22Illinois load. Each procurement plan shall analyze the
23projected balance of supply and demand for those retail
24customers to be included in the plan's electric supply service
25requirements over a 5-year period, with the first planning
26year beginning on June 1 of the year following the year in

 

 

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1which the plan is filed. The plan shall specifically identify
2the wholesale products to be procured following plan approval,
3and shall follow all the requirements set forth in the Public
4Utilities Act and all applicable State and federal laws,
5statutes, rules, or regulations, as well as Commission orders.
6Nothing in this Section precludes consideration of contracts
7longer than 5 years and related forecast data. Unless
8specified otherwise in this Section, in the procurement plan
9or in the implementing tariff, any procurement occurring in
10accordance with this plan shall be competitively bid through a
11request for proposals process. Approval and implementation of
12the procurement plan shall be subject to review and approval
13by the Commission according to the provisions set forth in
14this Section. A procurement plan shall include each of the
15following 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
12served more than 300,000 retail customers in this State shall
13purchase renewable energy credits from new renewable energy
14facilities constructed at or adjacent to the sites of
15coal-fueled electric generating facilities in this State in
16accordance with subsection (c-5) of Section 1-75 of the
17Illinois Power Agency Act. Except as expressly provided in
18this Section, the plans and procedures for such procurements
19shall not be included in the procurement plans provided for in
20this Section, but rather shall be conducted and implemented
21solely in accordance with subsection (c-5) of Section 1-75 of
22the 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
26to procurements conducted pursuant to subsection (c-5) of

 

 

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1Section 1-75 of the Illinois Power Agency Act. However, the
2Agency may retain a procurement administrator to assist the
3Agency in planning and carrying out the procurement events and
4implementing the other requirements specified in such
5subsection (c-5) of Section 1-75 of the Illinois Power Agency
6Act, with the costs incurred by the Agency for the procurement
7administrator to be recovered through fees charged to
8applicants for selection to sell and deliver renewable energy
9credits to electric utilities pursuant to subsection (c-5) of
10Section 1-75 of the Illinois Power Agency Act. The procurement
11process set forth in Section 1-75 of the Illinois Power Agency
12Act and subsection (e) of this Section shall be administered
13by a procurement administrator and monitored by a procurement
14monitor.
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
4process 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
25following 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,
2the procurement administrator shall submit a confidential
3report to the Commission. The report shall contain the results
4of the bidding for each of the products along with the
5procurement administrator's recommendation for the acceptance
6and rejection of bids based on the price benchmark criteria
7and other factors observed in the process. The procurement
8monitor also shall submit a confidential report to the
9Commission within 2 business days after opening the sealed
10bids. The report shall contain the procurement monitor's
11assessment of bidder behavior in the process as well as an
12assessment of the procurement administrator's compliance with
13the procurement process and rules. The Commission shall review
14the confidential reports submitted by the procurement
15administrator and procurement monitor, and shall accept or
16reject the recommendations of the procurement administrator
17within 2 business days after receipt of the reports.
18    (g) Within 3 business days after the Commission decision
19approving the results of a procurement event, the utility
20shall enter into binding contractual arrangements with the
21winning suppliers using the standard form contracts; except
22that the utility shall not be required either directly or
23indirectly to execute the contracts if a tariff that is
24consistent with subsection (l) of this Section has not been
25approved and placed into effect for that utility.
26    (h) For the procurement of standard wholesale products,

 

 

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1the names of the successful bidders and the load weighted
2average of the winning bid prices for each contract type and
3for each contract term shall be made available to the public at
4the time of Commission approval of a procurement event. For
5procurements conducted to meet the requirements of subsection
6(b) of Section 1-56 or subsection (c) of Section 1-75 of the
7Illinois Power Agency Act governed by the provisions of this
8Section, the address and nameplate capacity of the new
9renewable energy generating facility proposed by a winning
10bidder shall also be made available to the public at the time
11of Commission approval of a procurement event, along with the
12business address and contact information for any winning
13bidder. An estimate or approximation of the nameplate capacity
14of the new renewable energy generating facility may be
15disclosed if necessary to protect the confidentiality of
16individual bid prices.
17    The Commission, the procurement monitor, the procurement
18administrator, the Illinois Power Agency, and all participants
19in the procurement process shall maintain the confidentiality
20of all other supplier and bidding information in a manner
21consistent with all applicable laws, rules, regulations, and
22tariffs. Confidential information, including the confidential
23reports submitted by the procurement administrator and
24procurement monitor pursuant to subsection (f) of this
25Section, shall not be made publicly available and shall not be
26discoverable by any party in any proceeding, absent a

 

 

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1compelling demonstration of need, nor shall those reports be
2admissible in any proceeding other than one for law
3enforcement purposes.
4    (i) Within 2 business days after a Commission decision
5approving the results of a procurement event or such other
6date as may be required by the Commission from time to time,
7the utility shall file for informational purposes with the
8Commission its actual or estimated retail supply charges, as
9applicable, by customer supply group reflecting the costs
10associated with the procurement and computed in accordance
11with the tariffs filed pursuant to subsection (l) of this
12Section and approved by the Commission.
13    (j) Within 60 days following August 28, 2007 (the
14effective date of Public Act 95-481), each electric utility
15that on December 31, 2005 provided electric service to at
16least 100,000 customers in Illinois shall prepare and file
17with the Commission an initial procurement plan, which shall
18conform in all material respects to the requirements of the
19procurement plan set forth in subsection (b); provided,
20however, that the Illinois Power Agency Act shall not apply to
21the initial procurement plan prepared pursuant to this
22subsection. The initial procurement plan shall identify the
23portfolio of power and energy products to be procured and
24delivered for the period June 2008 through May 2009, and shall
25identify the proposed procurement administrator, who shall
26have the same experience and expertise as is required of a

 

 

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1procurement administrator hired pursuant to Section 1-75 of
2the Illinois Power Agency Act. Copies of the procurement plan
3shall be posted and made publicly available on the
4Commission's website. The initial procurement plan may include
5contracts 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
7under this Section and subsection (c-5) of Section 1-75 of the
8Illinois Power Agency Act, including, but not limited to, the
9costs of procuring power and energy demand-response resources
10under this Section and its costs for purchasing renewable
11energy credits pursuant to subsection (c-5) of Section 1-75 of
12the Illinois Power Agency Act. The utility shall file with the
13initial procurement plan its proposed tariffs through which
14its costs of procuring power that are incurred pursuant to a
15Commission-approved procurement plan and those other costs
16identified in this subsection (l), will be recovered. The
17tariffs shall include a formula rate or charge designed to
18pass through both the costs incurred by the utility in
19procuring a supply of electric power and energy for the
20applicable customer classes with no mark-up or return on the
21price paid by the utility for that supply, plus any just and
22reasonable costs that the utility incurs in arranging and
23providing for the supply of electric power and energy. The
24formula rate or charge shall also contain provisions that
25ensure that its application does not result in over or under
26recovery due to changes in customer usage and demand patterns,

 

 

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1and that provide for the correction, on at least an annual
2basis, of any accounting errors that may occur. A utility
3shall recover through the tariff all reasonable costs incurred
4to implement or comply with any procurement plan that is
5developed and put into effect pursuant to Section 1-75 of the
6Illinois Power Agency Act and this Section, and for the
7procurement of renewable energy credits pursuant to subsection
8(c-5) of Section 1-75 of the Illinois Power Agency Act,
9including any fees assessed by the Illinois Power Agency,
10costs associated with load balancing, and contingency plan
11costs. The electric utility shall also recover its full costs
12of procuring electric supply for which it contracted before
13the effective date of this Section in conjunction with the
14provision of full requirements service under fixed-price
15bundled service tariffs subsequent to December 31, 2006. All
16such costs shall be deemed to have been prudently incurred.
17The pass-through tariffs that are filed and approved pursuant
18to this Section shall not be subject to review under, or in any
19way limited by, Section 16-111(i) of this Act. All of the costs
20incurred by the electric utility associated with the purchase
21of zero emission credits in accordance with subsection (d-5)
22of Section 1-75 of the Illinois Power Agency Act, all costs
23incurred by the electric utility associated with the purchase
24of carbon mitigation credits in accordance with subsection
25(d-10) of Section 1-75 of the Illinois Power Agency Act, and,
26beginning June 1, 2017, all of the costs incurred by the

 

 

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1electric utility associated with the purchase of renewable
2energy resources in accordance with Sections 1-56 and 1-75 of
3the Illinois Power Agency Act, and all of the costs incurred by
4the electric utility in purchasing renewable energy credits in
5accordance with subsection (c-5) of Section 1-75 of the
6Illinois Power Agency Act, shall be recovered through the
7electric utility's tariffed charges applicable to all of its
8retail customers, as specified in subsection (k) or subsection
9(i-5), as applicable, of Section 16-108 of this Act, and shall
10not be recovered through the electric utility's tariffed
11charges for electric power and energy supply to its eligible
12retail customers.
13    (m) The Commission has the authority to adopt rules to
14carry out the provisions of this Section. For the public
15interest, safety, and welfare, the Commission also has
16authority to adopt rules to carry out the provisions of this
17Section on an emergency basis immediately following August 28,
182007 (the effective date of Public Act 95-481).
19    (n) Notwithstanding any other provision of this Act, any
20affiliated electric utilities that submit a single procurement
21plan covering their combined needs may procure for those
22combined needs in conjunction with that plan, and may enter
23jointly into power supply contracts, purchases, and other
24procurement arrangements, and allocate capacity and energy and
25cost responsibility therefor among themselves in proportion to
26their requirements.

 

 

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1    (o) On or before June 1 of each year, the Commission shall
2hold an informal hearing for the purpose of receiving comments
3on the prior year's procurement process and any
4recommendations for change.
5    (p) An electric utility subject to this Section may
6propose to invest, lease, own, or operate an electric
7generation facility as part of its procurement plan, provided
8the utility demonstrates that such facility is the least-cost
9option to provide electric service to those retail customers
10included in the plan's electric supply service requirements.
11If the facility is shown to be the least-cost option and is
12included in a procurement plan prepared in accordance with
13Section 1-75 of the Illinois Power Agency Act and this
14Section, then the electric utility shall make a filing
15pursuant to Section 8-406 of this Act, and may request of the
16Commission any statutory relief required thereunder. If the
17Commission grants all of the necessary approvals for the
18proposed facility, such supply shall thereafter be considered
19as a pre-existing contract under subsection (b) of this
20Section. The Commission shall in any order approving a
21proposal under this subsection specify how the utility will
22recover the prudently incurred costs of investing in, leasing,
23owning, or operating such generation facility through just and
24reasonable rates charged to those retail customers included in
25the plan's electric supply service requirements. Cost recovery
26for facilities included in the utility's procurement plan

 

 

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1pursuant to this subsection shall not be subject to review
2under or in any way limited by the provisions of Section
316-111(i) of this Act. Nothing in this Section is intended to
4prohibit a utility from filing for a fuel adjustment clause as
5is otherwise permitted under Section 9-220 of this Act.
6    (q) If the Illinois Power Agency filed with the
7Commission, under Section 16-111.5 of this Act, its proposed
8procurement plan for the period commencing June 1, 2017, and
9the Commission has not yet entered its final order approving
10the plan on or before the effective date of this amendatory Act
11of the 99th General Assembly, then the Illinois Power Agency
12shall file a notice of withdrawal with the Commission, after
13the effective date of this amendatory Act of the 99th General
14Assembly, to withdraw the proposed procurement of renewable
15energy resources to be approved under the plan, other than the
16procurement of renewable energy credits from distributed
17renewable energy generation devices using funds previously
18collected from electric utilities' retail customers that take
19service pursuant to electric utilities' hourly pricing tariff
20or tariffs and, for an electric utility that serves less than
21100,000 retail customers in the State, other than the
22procurement of renewable energy credits from distributed
23renewable energy generation devices. Upon receipt of the
24notice, the Commission shall enter an order that approves the
25withdrawal of the proposed procurement of renewable energy
26resources from the plan. The initially proposed procurement of

 

 

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1renewable energy resources shall not be approved or be the
2subject of any further hearing, investigation, proceeding, or
3order of any kind.
4    This amendatory Act of the 99th General Assembly preempts
5and supersedes any order entered by the Commission that
6approved the Illinois Power Agency's procurement plan for the
7period commencing June 1, 2017, to the extent it is
8inconsistent with the provisions of this amendatory Act of the
999th General Assembly. To the extent any previously entered
10order approved the procurement of renewable energy resources,
11the portion of that order approving the procurement shall be
12void, other than the procurement of renewable energy credits
13from distributed renewable energy generation devices using
14funds previously collected from electric utilities' retail
15customers that take service under electric utilities' hourly
16pricing tariff or tariffs and, for an electric utility that
17serves less than 100,000 retail customers in the State, other
18than the procurement of renewable energy credits for
19distributed 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
23suppliers.
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

 

 

SB3637- 209 -LRB103 38841 CES 68978 b

1    compliance with subsection (h) of this Section.
2    (b) An alternative retail electric supplier shall obtain
3verifiable authorization from a customer, in a form or manner
4approved by the Commission consistent with Section 2EE of the
5Consumer Fraud and Deceptive Business Practices Act, before
6the customer is switched from another supplier.
7    (c) No alternative retail electric supplier, or electric
8utility other than the electric utility in whose service area
9a customer is located, shall (i) enter into or employ any
10arrangements which have the effect of preventing a retail
11customer with a maximum electrical demand of less than one
12megawatt from having access to the services of the electric
13utility in whose service area the customer is located or (ii)
14charge retail customers for such access. This subsection shall
15not be construed to prevent an arms-length agreement between a
16supplier and a retail customer that sets a term of service,
17notice period for terminating service and provisions governing
18early termination through a tariff or contract as allowed by
19Section 16-119.
20    (d) An alternative retail electric supplier that is
21certified to serve residential or small commercial retail
22customers 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
12with the following requirements with respect to the marketing,
13offering and provision of products or services to residential
14and 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

 

 

SB3637- 212 -LRB103 38841 CES 68978 b

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

 

 

SB3637- 213 -LRB103 38841 CES 68978 b

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

 

 

SB3637- 214 -LRB103 38841 CES 68978 b

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

 

 

SB3637- 215 -LRB103 38841 CES 68978 b

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
5overall size or availability of a service offering by
6specifying one or more of the following: a maximum number of
7customers, maximum amount of electric load to be served, time
8period during which the offering will be available, or other
9comparable limitation, but not including the geographic
10locations of customers within the area which the alternative
11retail electric supplier is certificated to serve. The
12alternative retail electric supplier shall file the terms and
13conditions of such service offering including the applicable
14limitations with the Commission prior to making the service
15offering available to customers.
16    (g) Nothing in this Section shall be construed as
17preventing an alternative retail electric supplier, which is
18an affiliate of, or which contracts with, (i) an industry or
19trade organization or association, (ii) a membership
20organization or association that exists for a purpose other
21than the purchase of electricity, or (iii) another
22organization that meets criteria established in a rule adopted
23by the Commission, from offering through the organization or
24association services at prices, terms and conditions that are
25available solely to the members of the organization or
26association.

 

 

SB3637- 216 -LRB103 38841 CES 68978 b

1    (h) For all potentially eligible retail customers, as
2defined in Section 16-111.5, served by an alternative retail
3electric supplier, or electric utility other than the electric
4utility in whose service area a customer is located, such
5supplier or utility shall purchase products that include the
6same percentage of renewable energy resources, as defined in
7Section 1-10 of the Illinois Power Agency Act, as was procured
8for the utility in whose service area such customers are
9located for the immediately prior delivery year. Such clean
10energy shall include all environmental attributes as described
11in Section 16-111.5 and match the eligibility criteria of
12resources eligible for the renewable portfolio standard
13described in subsections (c)(I) and (c)(J) of Section 1-75 of
14the 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
18retail electric suppliers and electric utilities operating
19outside their service territories.
20    (a) An alternative retail electric supplier shall be
21responsible for procuring cost-effective renewable energy
22resources as required under item (5) of subsection (d) of
23Section 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

 

 

SB3637- 217 -LRB103 38841 CES 68978 b

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,

 

 

SB3637- 218 -LRB103 38841 CES 68978 b

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

 

 

SB3637- 219 -LRB103 38841 CES 68978 b

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

 

 

SB3637- 226 -LRB103 38841 CES 68978 b

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
21September 1, 2010 and by September 1 of each year thereafter,
22prepare and submit to the Commission a report, in a format to
23be specified by the Commission, that provides information
24certifying compliance by the alternative retail electric
25supplier with this Section, including copies of all PJM-GATS
26and M-RETS reports, and documentation relating to banking,

 

 

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1retiring renewable energy credits, and any other information
2that the Commission determines necessary to ensure compliance
3with this Section.
4    An alternative retail electric supplier may file
5commercially or financially sensitive information or trade
6secrets with the Commission as provided under the rules of the
7Commission. To be filed confidentially, the information shall
8be accompanied by an affidavit that sets forth both the
9reasons for the confidentiality and a public synopsis of the
10information.
11    (f) The Commission may initiate a contested case to review
12allegations that the alternative retail electric supplier has
13violated this Section, including an order issued or rule
14promulgated under this Section. In any such proceeding, the
15alternative retail electric supplier shall have the burden of
16proof. If the Commission finds, after notice and hearing, that
17an alternative retail electric supplier has violated this
18Section, then the Commission shall issue an order requiring
19the 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

 

 

SB3637- 229 -LRB103 38841 CES 68978 b

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
4with the renewable energy resource portfolio requirement or
5capacity portfolio requirement in this Section more than once
6in a 5-year period, then the Commission shall revoke the
7alternative electric supplier's certificate of service
8authority. The Commission shall not accept an application for
9a certificate of service authority from an alternative retail
10electric supplier that has lost certification under this
11subsection (f), or any corporate affiliate thereof, for at
12least one year after the date of revocation.
13    (g) All of the provisions of this Section apply to
14electric utilities operating outside their service area except
15under item (2) of subsection (a) of this Section the quantity
16of renewable energy resources shall be measured as a
17percentage of the actual amount of electricity
18(megawatt-hours) supplied in the State outside of the
19utility's service territory during the 12-month period June 1
20through May 31, commencing June 1, 2009, and the comparable
2112-month period in each year thereafter except as provided in
22item (6) of subsection (a) of this Section.
23    If any such utility fails to procure the requisite
24quantity of renewable energy resources by the annual deadline,
25then the Commission shall require the utility to double the
26alternative compliance payment that would otherwise be

 

 

SB3637- 230 -LRB103 38841 CES 68978 b

1required to bring the utility into compliance with this
2Section.
3    If any such utility fails to comply with the renewable
4energy resource portfolio requirement in this Section more
5than once in a 5-year period, then the Commission shall order
6the utility to cease all sales outside of the utility's
7service territory for a period of at least one year.
8    (h) The provisions of this Section and the provisions of
9subsection (d) of Section 16-115 of this Act relating to
10procurement of renewable energy resources shall not apply to
11an alternative retail electric supplier that operates a
12combined heat and power system in this State or that has a
13corporate affiliate that operates such a combined heat and
14power system in this State that supplies electricity primarily
15to or for the benefit of: (i) facilities owned by the supplier,
16its subsidiary, or other corporate affiliate; (ii) facilities
17electrically integrated with the electrical system of
18facilities owned by the supplier, its subsidiary, or other
19corporate affiliate; or (iii) facilities that are adjacent to
20the site on which the combined heat and power system is
21located.
22    (i) The obligations of alternative retail electric
23suppliers and electric utilities operating outside their
24service territories to procure renewable energy resources,
25make alternative compliance payments, and file annual reports,
26and the obligations of the Commission to determine and post

 

 

SB3637- 231 -LRB103 38841 CES 68978 b

1alternative compliance payment rates, shall terminate after
2May 31, 2019, provided that alternative retail electric
3suppliers and electric utilities operating outside their
4service territories shall be obligated to make all alternative
5compliance payments that they were obligated to pay for
6periods through and including May 31, 2019, but were not paid
7as of that date. The Commission shall continue to enforce the
8payment of unpaid alternative compliance payments in
9accordance with subsections (f) and (g) of this Section. All
10alternative compliance payments made after May 31, 2016 shall
11be remitted to the applicable electric utility and used to
12purchase renewable energy credits, in accordance with Section
131-75 of the Illinois Power Agency Act.
14    This subsection (i) is intended to accommodate the
15transition to the procurement of renewable energy resources
16for all retail customers in the amounts specified under
17subsection (c) of Section 1-75 of the Illinois Power Agency
18Act and Section 16-111.5 of this Act, including but not
19limited to the transition to a single charge applicable to all
20retail customers to recover the costs of these resources. Each
21alternative retail electric supplier shall certify in its
22annual reports filed pursuant to subsection (e) of this
23Section after May 31, 2019, that its retail customers are not
24paying the costs of alternative compliance payments or
25renewable energy resources that the alternative retail
26electric supplier is not required to remit or purchase under

 

 

SB3637- 232 -LRB103 38841 CES 68978 b

1this Section. The Commission shall have the authority to
2initiate an emergency rulemaking to adopt rules regarding such
3certification.
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
7Electric Supplier Act, the Illinois Municipal Code, the
8Municipal and Cooperative Electric Utility Planning and
9Transparency Act, and this Article XVII, the Commission, or
10any other agency or subdivision thereof of the State of
11Illinois or any private entity shall have no jurisdiction over
12any electric cooperative or municipal system regardless of
13whether any election or elections as provided for herein have
14been made, and all control regarding an electric cooperative
15or municipal system shall be vested in the electric
16cooperative's board of directors or trustees or the applicable
17governing 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
20Section 5-5-5 as follows:
 
21    (735 ILCS 30/5-5-5)
22    Sec. 5-5-5. Exercise of the power of eminent domain;
23public use; blight.

 

 

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1    (a) In addition to all other limitations and requirements,
2a condemning authority may not take or damage property by the
3exercise of the power of eminent domain unless it is for a
4public use, as set forth in this Section.
5    (a-5) Subsections (b), (c), (d), (e), and (f) of this
6Section do not apply to the acquisition of property under the
7O'Hare Modernization Act. A condemning authority may exercise
8the power of eminent domain for the acquisition or damaging of
9property under the O'Hare Modernization Act as provided for by
10law in effect prior to the effective date of this Act.
11    (a-10) Subsections (b), (c), (d), (e), and (f) of this
12Section do not apply to the acquisition or damaging of
13property in furtherance of the goals and objectives of an
14existing tax increment allocation redevelopment plan. A
15condemning authority may exercise the power of eminent domain
16for the acquisition of property in furtherance of an existing
17tax increment allocation redevelopment plan as provided for by
18law in effect prior to the effective date of this Act.
19    As used in this subsection, "existing tax increment
20allocation redevelopment plan" means a redevelopment plan that
21was adopted under the Tax Increment Allocation Redevelopment
22Act (Article 11, Division 74.4 of the Illinois Municipal Code)
23prior to April 15, 2006 and for which property assembly costs
24were, before that date, included as a budget line item in the
25plan or described in the narrative portion of the plan as part
26of the redevelopment project, but does not include (i) any

 

 

SB3637- 234 -LRB103 38841 CES 68978 b

1additional area added to the redevelopment project area on or
2after April 15, 2006, (ii) any subsequent extension of the
3completion date of a redevelopment plan beyond the estimated
4completion date established in that plan prior to April 15,
52006, (iii) any acquisition of property in a conservation area
6for which the condemnation complaint is filed more than 12
7years after the effective date of this Act, or (iv) any
8acquisition of property in an industrial park conservation
9area.
10    As used in this subsection, "conservation area" and
11"industrial park conservation area" have the same meanings as
12under Section 11-74.4-3 of the Illinois Municipal Code.
13    (b) If the exercise of eminent domain authority is to
14acquire property for public ownership and control, then the
15condemning authority must prove that (i) the acquisition of
16the property is necessary for a public purpose and (ii) the
17acquired property will be owned and controlled by the
18condemning 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
21subsection (d), (e), or (f) and the condemning authority
22elects to proceed under one of those subsections, if the
23exercise of eminent domain authority is to acquire property
24for private ownership or control, or both, then the condemning
25authority must prove by clear and convincing evidence that the
26acquisition of the property for private ownership or control

 

 

SB3637- 235 -LRB103 38841 CES 68978 b

1is (i) primarily for the benefit, use, or enjoyment of the
2public and (ii) necessary for a public purpose.
3    An acquisition of property primarily for the purpose of
4the elimination of blight is rebuttably presumed to be for a
5public purpose and primarily for the benefit, use, or
6enjoyment of the public under this subsection.
7    Any challenge to the existence of blighting factors
8alleged in a complaint to condemn under this subsection shall
9be raised within 6 months of the filing date of the complaint
10to condemn, and if not raised within that time the right to
11challenge the existence of those blighting factors shall be
12deemed waived.
13    Evidence that the Illinois Commerce Commission has granted
14a certificate or otherwise made a finding of public
15convenience and necessity for an acquisition of property (or
16any right or interest in property) for private ownership or
17control (including, without limitation, an acquisition for
18which the use of eminent domain is authorized under the Public
19Utilities Act, the Telephone Company Act, or the Electric
20Supplier Act) to be used for utility purposes creates a
21rebuttable presumption that such acquisition of that property
22(or right or interest in property) is (i) primarily for the
23benefit, use, or enjoyment of the public and (ii) necessary
24for a public purpose.
25    In the case of an acquisition of property (or any right or
26interest in property) for private ownership or control to be

 

 

SB3637- 236 -LRB103 38841 CES 68978 b

1used for utility, pipeline, or railroad purposes for which no
2certificate or finding of public convenience and necessity by
3the Illinois Commerce Commission is required, evidence that
4the acquisition is one for which the use of eminent domain is
5authorized under one of the following laws creates a
6rebuttable presumption that the acquisition of that property
7(or right or interest in property) is (i) primarily for the
8benefit, use, or enjoyment of the public and (ii) necessary
9for 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
23acquire property for private ownership or control and if the
24primary basis for the acquisition is the elimination of blight
25and the condemning authority elects to proceed under this
26subsection, then the condemning authority must: (i) prove by a

 

 

SB3637- 237 -LRB103 38841 CES 68978 b

1preponderance of the evidence that acquisition of the property
2for private ownership or control is necessary for a public
3purpose; (ii) prove by a preponderance of the evidence that
4the property to be acquired is located in an area that is
5currently designated as a blighted area or conservation area
6under an applicable statute; (iii) if the existence of blight
7or blighting factors is challenged in an appropriate motion
8filed within 6 months after the date of filing of the complaint
9to condemn, prove by a preponderance of the evidence that the
10required blighting factors existed in the area so designated
11(but not necessarily in the particular property to be
12acquired) at the time of the designation under item (ii) or at
13any time thereafter; and (iv) prove by a preponderance of the
14evidence 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

 

 

SB3637- 238 -LRB103 38841 CES 68978 b

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
19official act designating an area as blighted is not prima
20facie evidence of the existence of blight. A finding by the
21court in a condemnation proceeding that a property or area has
22not been proven to be blighted does not apply to any other case
23or undermine the designation of a blighted area or
24conservation area or the determination of the existence of
25blight for any other purpose or under any other statute,
26including without limitation under the Tax Increment

 

 

SB3637- 239 -LRB103 38841 CES 68978 b

1Allocation Redevelopment Act (Article 11, Division 74.4 of the
2Illinois Municipal Code).
3    Any challenge to the existence of blighting factors
4alleged in a complaint to condemn under this subsection shall
5be raised within 6 months of the filing date of the complaint
6to condemn, and if not raised within that time the right to
7challenge the existence of those blighting factors shall be
8deemed waived.
9    (e) If the exercise of eminent domain authority is to
10acquire property for private ownership or control and if the
11primary purpose of the acquisition is one of the purposes
12specified in item (iii) of this subsection and the condemning
13authority elects to proceed under this subsection, then the
14condemning authority must prove by a preponderance of the
15evidence that: (i) the acquisition of the property is
16necessary for a public purpose; (ii) an enforceable written
17agreement, deed restriction, or similar encumbrance has been
18or will be executed and recorded against the acquired property
19to assure that the project and the use of the property remain
20consistent with the applicable purpose specified in item (iii)
21of this subsection for a period of at least 40 years, which
22execution and recording shall be included as a requirement in
23any 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

 

 

SB3637- 240 -LRB103 38841 CES 68978 b

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
8acquire property for public ownership and private control and
9if the primary purpose of the acquisition is one of the
10purposes specified in item (iii) of this subsection and the
11condemning authority elects to proceed under this subsection,
12then the condemning authority must prove by a preponderance of
13the evidence that: (i) the acquisition of the property is
14necessary for a public purpose; (ii) the acquired property
15will be owned by the condemning authority or another
16governmental entity; and (iii) the acquired property will be
17controlled by a private party that operates a business or
18facility related to the condemning authority's operation of a
19university, medical district, hospital, exposition or
20convention center, mass transportation facility, or airport,
21including, but not limited to, a medical clinic, research and
22development center, food or commercial concession facility,
23social service facility, maintenance or storage facility,
24cargo facility, rental car facility, bus facility, taxi
25facility, flight kitchen, fixed based operation, parking
26facility, refueling facility, water supply facility, and

 

 

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1railroad tracks and stations.
2    (f-5) For all acquisitions governed by subsection (c)
3where the property, or any right or interest in property, is to
4be used for utility purposes, and where the condemning
5authority is an entity required to submit an integrated
6resource plan under the Municipal and Cooperative Electric
7Utility Planning and Transparency Act, the rebuttable
8presumption described in subsection (c) shall only apply if
9the most recent integrated resource plan filed by the
10condemning authority identified the facility or articulated a
11need for a facility of similar capacity and type to the
12facility for which the property or right or interest is
13sought.
14    (g) This Article is a limitation on the exercise of the
15power of eminent domain, but is not an independent grant of
16authority to exercise the power of eminent domain.
17(Source: P.A. 94-1055, eff. 1-1-07.)

 

 

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1 INDEX
2 Statutes amended in order of appearance
3    New Act
4    5 ILCS 120/2from Ch. 102, par. 42
5    20 ILCS 3855/1-5
6    20 ILCS 3855/1-20
7    65 ILCS 5/11-119.1-4from Ch. 24, par. 11-119.1-4
8    65 ILCS 5/11-119.1-5.5 new
9    65 ILCS 5/11-119.1-10from Ch. 24, par. 11-119.1-10
10    220 ILCS 5/3-105from Ch. 111 2/3, par. 3-105
11    220 ILCS 5/8-103B
12    220 ILCS 5/16-107.5
13    220 ILCS 5/16-107.8 new
14    220 ILCS 5/16-111.5
15    220 ILCS 5/16-115A
16    220 ILCS 5/16-115D
17    220 ILCS 5/17-500
18    735 ILCS 30/5-5-5