Bill Text: IL HB2640 | 2021-2022 | 102nd General Assembly | Introduced


Bill Title: Amends the Illinois Enterprise Zone Act. Provides that a business that intends to establish a new utility-scale solar power facility may apply for a high impact business designation. Amends the Illinois Power Agency Act. Increases the long-term renewable procurement plan goals after the 2025 delivery year. Requires the long-term renewable procurement plan to include the procurement of new renewable energy credits. Provides that the Adjustable Block program shall be designed to be continuously open. Authorizes utilities to recover certain costs related to the Adjustable Block program. Excludes certain costs from a limitation on the costs of the Adjustable Block program. Makes other changes concerning the Adjustable Block program. Amends the Public Utilities Act. Requires the Illinois Commerce Commission to open a proceeding to update the interconnection standards and applicable utility tariffs. Requires the Commission to revise certain standards for interconnection based on specified criteria. Establishes an interconnection working group. Makes changes to provisions concerning net metering and the distributed generation rebate. Requires the Commission, in consultation with the Illinois Power Agency, to study and produce a report analyzing the potential for and barriers to the implementation of energy storage in Illinois. Requires the Agency to include a plan to procure energy from energy storage resources as part of its procurement plan for 2021. Extends a provision concerning a review, reconciliation, and true-up associated with renewable energy resources' collections and costs. Makes other changes. Amends the Illinois Administrative Procedure Act to authorize emergency rulemaking. Effective immediately.

Spectrum: Partisan Bill (Democrat 4-0)

Status: (Introduced) 2021-04-23 - Rule 19(a) / Re-referred to Rules Committee [HB2640 Detail]

Download: Illinois-2021-HB2640-Introduced.html


102ND GENERAL ASSEMBLY
State of Illinois
2021 and 2022
HB2640

Introduced , by Rep. William Davis

SYNOPSIS AS INTRODUCED:
See Index

Amends the Illinois Enterprise Zone Act. Provides that a business that intends to establish a new utility-scale solar power facility may apply for a high impact business designation. Amends the Illinois Power Agency Act. Increases the long-term renewable procurement plan goals after the 2025 delivery year. Requires the long-term renewable procurement plan to include the procurement of new renewable energy credits. Provides that the Adjustable Block program shall be designed to be continuously open. Authorizes utilities to recover certain costs related to the Adjustable Block program. Excludes certain costs from a limitation on the costs of the Adjustable Block program. Makes other changes concerning the Adjustable Block program. Amends the Public Utilities Act. Requires the Illinois Commerce Commission to open a proceeding to update the interconnection standards and applicable utility tariffs. Requires the Commission to revise certain standards for interconnection based on specified criteria. Establishes an interconnection working group. Makes changes to provisions concerning net metering and the distributed generation rebate. Requires the Commission, in consultation with the Illinois Power Agency, to study and produce a report analyzing the potential for and barriers to the implementation of energy storage in Illinois. Requires the Agency to include a plan to procure energy from energy storage resources as part of its procurement plan for 2021. Extends a provision concerning a review, reconciliation, and true-up associated with renewable energy resources' collections and costs. Makes other changes. Amends the Illinois Administrative Procedure Act to authorize emergency rulemaking. Effective immediately.
LRB102 13765 SPS 19115 b
FISCAL NOTE ACT MAY APPLY

A BILL FOR

HB2640LRB102 13765 SPS 19115 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 5. The Illinois Administrative Procedure Act is
5amended by adding Section 5-45.8 as follows:
6 (5 ILCS 100/5-45.8 new)
7 Sec. 5-45.8. Emergency rulemaking; Illinois Commerce
8Commission. To provide for the expeditious and timely
9implementation of the provisions of this amendatory Act of the
10102nd General Assembly, emergency rules implementing the
11changes to Section 16-107.5 of the Public Utilities Act may be
12adopted in accordance with Section 5-45 by the Illinois
13Commerce Commission. The adoption of emergency rules
14authorized by Section 5-45 and this Section is deemed to be
15necessary for the public interest, safety, and welfare.
16 This Section is repealed on January 1, 2027.
17 Section 10. The Illinois Enterprise Zone Act is amended by
18changing Section 5.5 as follows:
19 (20 ILCS 655/5.5) (from Ch. 67 1/2, par. 609.1)
20 Sec. 5.5. High Impact Business.
21 (a) In order to respond to unique opportunities to assist

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1in the encouragement, development, growth, and expansion of
2the private sector through large scale investment and
3development projects, the Department is authorized to receive
4and approve applications for the designation of "High Impact
5Businesses" in Illinois subject to the following conditions:
6 (1) such applications may be submitted at any time
7 during the year;
8 (2) such business is not located, at the time of
9 designation, in an enterprise zone designated pursuant to
10 this Act;
11 (3) the business intends to do one or more of the
12 following:
13 (A) the business intends to make a minimum
14 investment of $12,000,000 which will be placed in
15 service in qualified property and intends to create
16 500 full-time equivalent jobs at a designated location
17 in Illinois or intends to make a minimum investment of
18 $30,000,000 which will be placed in service in
19 qualified property and intends to retain 1,500
20 full-time retained jobs at a designated location in
21 Illinois. The business must certify in writing that
22 the investments would not be placed in service in
23 qualified property and the job creation or job
24 retention would not occur without the tax credits and
25 exemptions set forth in subsection (b) of this
26 Section. The terms "placed in service" and "qualified

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1 property" have the same meanings as described in
2 subsection (h) of Section 201 of the Illinois Income
3 Tax Act; or
4 (B) the business intends to establish a new
5 electric generating facility at a designated location
6 in Illinois. "New electric generating facility", for
7 purposes of this Section, means a newly-constructed
8 electric generation plant or a newly-constructed
9 generation capacity expansion at an existing electric
10 generation plant, including the transmission lines and
11 associated equipment that transfers electricity from
12 points of supply to points of delivery, and for which
13 such new foundation construction commenced not sooner
14 than July 1, 2001. Such facility shall be designed to
15 provide baseload electric generation and shall operate
16 on a continuous basis throughout the year; and (i)
17 shall have an aggregate rated generating capacity of
18 at least 1,000 megawatts for all new units at one site
19 if it uses natural gas as its primary fuel and
20 foundation construction of the facility is commenced
21 on or before December 31, 2004, or shall have an
22 aggregate rated generating capacity of at least 400
23 megawatts for all new units at one site if it uses coal
24 or gases derived from coal as its primary fuel and
25 shall support the creation of at least 150 new
26 Illinois coal mining jobs, or (ii) shall be funded

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1 through a federal Department of Energy grant before
2 December 31, 2010 and shall support the creation of
3 Illinois coal-mining jobs, or (iii) shall use coal
4 gasification or integrated gasification-combined cycle
5 units that generate electricity or chemicals, or both,
6 and shall support the creation of Illinois coal-mining
7 jobs. The business must certify in writing that the
8 investments necessary to establish a new electric
9 generating facility would not be placed in service and
10 the job creation in the case of a coal-fueled plant
11 would not occur without the tax credits and exemptions
12 set forth in subsection (b-5) of this Section. The
13 term "placed in service" has the same meaning as
14 described in subsection (h) of Section 201 of the
15 Illinois Income Tax Act; or
16 (B-5) the business intends to establish a new
17 gasification facility at a designated location in
18 Illinois. As used in this Section, "new gasification
19 facility" means a newly constructed coal gasification
20 facility that generates chemical feedstocks or
21 transportation fuels derived from coal (which may
22 include, but are not limited to, methane, methanol,
23 and nitrogen fertilizer), that supports the creation
24 or retention of Illinois coal-mining jobs, and that
25 qualifies for financial assistance from the Department
26 before December 31, 2010. A new gasification facility

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1 does not include a pilot project located within
2 Jefferson County or within a county adjacent to
3 Jefferson County for synthetic natural gas from coal;
4 or
5 (C) the business intends to establish production
6 operations at a new coal mine, re-establish production
7 operations at a closed coal mine, or expand production
8 at an existing coal mine at a designated location in
9 Illinois not sooner than July 1, 2001; provided that
10 the production operations result in the creation of
11 150 new Illinois coal mining jobs as described in
12 subdivision (a)(3)(B) of this Section, and further
13 provided that the coal extracted from such mine is
14 utilized as the predominant source for a new electric
15 generating facility. The business must certify in
16 writing that the investments necessary to establish a
17 new, expanded, or reopened coal mine would not be
18 placed in service and the job creation would not occur
19 without the tax credits and exemptions set forth in
20 subsection (b-5) of this Section. The term "placed in
21 service" has the same meaning as described in
22 subsection (h) of Section 201 of the Illinois Income
23 Tax Act; or
24 (D) the business intends to construct new
25 transmission facilities or upgrade existing
26 transmission facilities at designated locations in

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1 Illinois, for which construction commenced not sooner
2 than July 1, 2001. For the purposes of this Section,
3 "transmission facilities" means transmission lines
4 with a voltage rating of 115 kilovolts or above,
5 including associated equipment, that transfer
6 electricity from points of supply to points of
7 delivery and that transmit a majority of the
8 electricity generated by a new electric generating
9 facility designated as a High Impact Business in
10 accordance with this Section. The business must
11 certify in writing that the investments necessary to
12 construct new transmission facilities or upgrade
13 existing transmission facilities would not be placed
14 in service without the tax credits and exemptions set
15 forth in subsection (b-5) of this Section. The term
16 "placed in service" has the same meaning as described
17 in subsection (h) of Section 201 of the Illinois
18 Income Tax Act; or
19 (E) the business intends to establish a new wind
20 power facility at a designated location in Illinois.
21 For purposes of this Section, "new wind power
22 facility" means a newly constructed electric
23 generation facility, or a newly constructed expansion
24 of an existing electric generation facility, placed in
25 service on or after July 1, 2009, that generates
26 electricity using wind energy devices, and such

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1 facility shall be deemed to include all associated
2 transmission lines, substations, and other equipment
3 related to the generation of electricity from wind
4 energy devices. For purposes of this Section, "wind
5 energy device" means any device, with a nameplate
6 capacity of at least 0.5 megawatts, that is used in the
7 process of converting kinetic energy from the wind to
8 generate electricity; or
9 (E-5) the business intends to establish a new
10 utility-scale solar facility at a designated location
11 in Illinois. For purposes of this Section, "new
12 utility-scale solar power facility" means a newly
13 constructed electric generation facility, or a newly
14 constructed expansion of an existing electric
15 generation facility, placed in service on or after
16 July 1, 2021, that (i) generates electricity using
17 photovoltaic cells and (ii) has a nameplate capacity
18 that is greater than 2,000 kilowatts, and such
19 facility shall be deemed to include all associated
20 transmission lines, substations, and other equipment
21 related to the generation of electricity from
22 photovoltaic cells; or
23 (F) the business commits to (i) make a minimum
24 investment of $500,000,000, which will be placed in
25 service in a qualified property, (ii) create 125
26 full-time equivalent jobs at a designated location in

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1 Illinois, (iii) establish a fertilizer plant at a
2 designated location in Illinois that complies with the
3 set-back standards as described in Table 1: Initial
4 Isolation and Protective Action Distances in the 2012
5 Emergency Response Guidebook published by the United
6 States Department of Transportation, (iv) pay a
7 prevailing wage for employees at that location who are
8 engaged in construction activities, and (v) secure an
9 appropriate level of general liability insurance to
10 protect against catastrophic failure of the fertilizer
11 plant or any of its constituent systems; in addition,
12 the business must agree to enter into a construction
13 project labor agreement including provisions
14 establishing wages, benefits, and other compensation
15 for employees performing work under the project labor
16 agreement at that location; for the purposes of this
17 Section, "fertilizer plant" means a newly constructed
18 or upgraded plant utilizing gas used in the production
19 of anhydrous ammonia and downstream nitrogen
20 fertilizer products for resale; for the purposes of
21 this Section, "prevailing wage" means the hourly cash
22 wages plus fringe benefits for training and
23 apprenticeship programs approved by the U.S.
24 Department of Labor, Bureau of Apprenticeship and
25 Training, health and welfare, insurance, vacations and
26 pensions paid generally, in the locality in which the

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1 work is being performed, to employees engaged in work
2 of a similar character on public works; this paragraph
3 (F) applies only to businesses that submit an
4 application to the Department within 60 days after
5 July 25, 2013 (the effective date of Public Act
6 98-109) this amendatory Act of the 98th General
7 Assembly; and
8 (4) no later than 90 days after an application is
9 submitted, the Department shall notify the applicant of
10 the Department's determination of the qualification of the
11 proposed High Impact Business under this Section.
12 (b) Businesses designated as High Impact Businesses
13pursuant to subdivision (a)(3)(A) of this Section shall
14qualify for the credits and exemptions described in the
15following Acts: Section 9-222 and Section 9-222.1A of the
16Public Utilities Act, subsection (h) of Section 201 of the
17Illinois Income Tax Act, and Section 1d of the Retailers'
18Occupation Tax Act; provided that these credits and exemptions
19described in these Acts shall not be authorized until the
20minimum investments set forth in subdivision (a)(3)(A) of this
21Section have been placed in service in qualified properties
22and, in the case of the exemptions described in the Public
23Utilities Act and Section 1d of the Retailers' Occupation Tax
24Act, the minimum full-time equivalent jobs or full-time
25retained jobs set forth in subdivision (a)(3)(A) of this
26Section have been created or retained. Businesses designated

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1as High Impact Businesses under this Section shall also
2qualify for the exemption described in Section 5l of the
3Retailers' Occupation Tax Act. The credit provided in
4subsection (h) of Section 201 of the Illinois Income Tax Act
5shall be applicable to investments in qualified property as
6set forth in subdivision (a)(3)(A) of this Section.
7 (b-5) Businesses designated as High Impact Businesses
8pursuant to subdivisions (a)(3)(B), (a)(3)(B-5), (a)(3)(C),
9and (a)(3)(D) of this Section shall qualify for the credits
10and exemptions described in the following Acts: Section 51 of
11the Retailers' Occupation Tax Act, Section 9-222 and Section
129-222.1A of the Public Utilities Act, and subsection (h) of
13Section 201 of the Illinois Income Tax Act; however, the
14credits and exemptions authorized under Section 9-222 and
15Section 9-222.1A of the Public Utilities Act, and subsection
16(h) of Section 201 of the Illinois Income Tax Act shall not be
17authorized until the new electric generating facility, the new
18gasification facility, the new transmission facility, or the
19new, expanded, or reopened coal mine is operational, except
20that a new electric generating facility whose primary fuel
21source is natural gas is eligible only for the exemption under
22Section 5l of the Retailers' Occupation Tax Act.
23 (b-6) Businesses designated as High Impact Businesses
24pursuant to subdivision (a)(3)(E) of this Section shall
25qualify for the exemptions described in Section 5l of the
26Retailers' Occupation Tax Act; any business so designated as a

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1High Impact Business being, for purposes of this Section, a
2"Wind Energy Business".
3 (b-7) Beginning on January 1, 2021, businesses designated
4as High Impact Businesses by the Department shall qualify for
5the High Impact Business construction jobs credit under
6subsection (h-5) of Section 201 of the Illinois Income Tax Act
7if the business meets the criteria set forth in subsection (i)
8of this Section. The total aggregate amount of credits awarded
9under the Blue Collar Jobs Act (Article 20 of Public Act 101-9
10this amendatory Act of the 101st General Assembly) shall not
11exceed $20,000,000 in any State fiscal year.
12 (c) High Impact Businesses located in federally designated
13foreign trade zones or sub-zones are also eligible for
14additional credits, exemptions and deductions as described in
15the following Acts: Section 9-221 and Section 9-222.1 of the
16Public Utilities Act; and subsection (g) of Section 201, and
17Section 203 of the Illinois Income Tax Act.
18 (d) Except for businesses contemplated under subdivision
19(a)(3)(E) of this Section, existing Illinois businesses which
20apply for designation as a High Impact Business must provide
21the Department with the prospective plan for which 1,500
22full-time retained jobs would be eliminated in the event that
23the business is not designated.
24 (e) Except for new wind power facilities contemplated
25under subdivision (a)(3)(E) of this Section, new proposed
26facilities which apply for designation as High Impact Business

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1must provide the Department with proof of alternative
2non-Illinois sites which would receive the proposed investment
3and job creation in the event that the business is not
4designated as a High Impact Business.
5 (f) Except for businesses contemplated under subdivision
6(a)(3)(E) of this Section, in the event that a business is
7designated a High Impact Business and it is later determined
8after reasonable notice and an opportunity for a hearing as
9provided under the Illinois Administrative Procedure Act, that
10the business would have placed in service in qualified
11property the investments and created or retained the requisite
12number of jobs without the benefits of the High Impact
13Business designation, the Department shall be required to
14immediately revoke the designation and notify the Director of
15the Department of Revenue who shall begin proceedings to
16recover all wrongfully exempted State taxes with interest. The
17business shall also be ineligible for all State funded
18Department programs for a period of 10 years.
19 (g) The Department shall revoke a High Impact Business
20designation if the participating business fails to comply with
21the terms and conditions of the designation. However, the
22penalties for new wind power facilities or Wind Energy
23Businesses or new utility-scale solar power facilities for
24failure to comply with any of the terms or conditions of the
25Illinois Prevailing Wage Act shall be only those penalties
26identified in the Illinois Prevailing Wage Act, and the

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1Department shall not revoke a High Impact Business designation
2as a result of the failure to comply with any of the terms or
3conditions of the Illinois Prevailing Wage Act in relation to
4a new wind power facility or a Wind Energy Business or new
5utility-scale solar power facility.
6 (h) Prior to designating a business, the Department shall
7provide the members of the General Assembly and Commission on
8Government Forecasting and Accountability with a report
9setting forth the terms and conditions of the designation and
10guarantees that have been received by the Department in
11relation to the proposed business being designated.
12 (i) High Impact Business construction jobs credit.
13Beginning on January 1, 2021, a High Impact Business may
14receive a tax credit against the tax imposed under subsections
15(a) and (b) of Section 201 of the Illinois Income Tax Act in an
16amount equal to 50% of the amount of the incremental income tax
17attributable to High Impact Business construction jobs credit
18employees employed in the course of completing a High Impact
19Business construction jobs project. However, the High Impact
20Business construction jobs credit may equal 75% of the amount
21of the incremental income tax attributable to High Impact
22Business construction jobs credit employees if the High Impact
23Business construction jobs credit project is located in an
24underserved area.
25 The Department shall certify to the Department of Revenue:
26(1) the identity of taxpayers that are eligible for the High

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1Impact Business construction jobs credit; and (2) the amount
2of High Impact Business construction jobs credits that are
3claimed pursuant to subsection (h-5) of Section 201 of the
4Illinois Income Tax Act in each taxable year. Any business
5entity that receives a High Impact Business construction jobs
6credit shall maintain a certified payroll pursuant to
7subsection (j) of this Section.
8 As used in this subsection (i):
9 "High Impact Business construction jobs credit" means an
10amount equal to 50% (or 75% if the High Impact Business
11construction project is located in an underserved area) of the
12incremental income tax attributable to High Impact Business
13construction job employees. The total aggregate amount of
14credits awarded under the Blue Collar Jobs Act (Article 20 of
15Public Act 101-9 this amendatory Act of the 101st General
16Assembly) shall not exceed $20,000,000 in any State fiscal
17year
18 "High Impact Business construction job employee" means a
19laborer or worker who is employed by an Illinois contractor or
20subcontractor in the actual construction work on the site of a
21High Impact Business construction job project.
22 "High Impact Business construction jobs project" means
23building a structure or building or making improvements of any
24kind to real property, undertaken and commissioned by a
25business that was designated as a High Impact Business by the
26Department. The term "High Impact Business construction jobs

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1project" does not include the routine operation, routine
2repair, or routine maintenance of existing structures,
3buildings, or real property.
4 "Incremental income tax" means the total amount withheld
5during the taxable year from the compensation of High Impact
6Business construction job employees.
7 "Underserved area" means a geographic area that meets one
8or more of the following conditions:
9 (1) the area has a poverty rate of at least 20%
10 according to the latest federal decennial census;
11 (2) 75% or more of the children in the area
12 participate in the federal free lunch program according to
13 reported statistics from the State Board of Education;
14 (3) at least 20% of the households in the area receive
15 assistance under the Supplemental Nutrition Assistance
16 Program (SNAP); or
17 (4) the area has an average unemployment rate, as
18 determined by the Illinois Department of Employment
19 Security, that is more than 120% of the national
20 unemployment average, as determined by the U.S. Department
21 of Labor, for a period of at least 2 consecutive calendar
22 years preceding the date of the application.
23 (j) Each contractor and subcontractor who is engaged in
24and executing a High Impact Business Construction jobs
25project, as defined under subsection (i) of this Section, for
26a business that is entitled to a credit pursuant to subsection

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1(i) of this Section shall:
2 (1) make and keep, for a period of 5 years from the
3 date of the last payment made on or after June 5, 2021 (the
4 effective date of Public Act 101-9) this amendatory Act of
5 the 101st General Assembly on a contract or subcontract
6 for a High Impact Business Construction Jobs Project,
7 records for all laborers and other workers employed by the
8 contractor or subcontractor on the project; the records
9 shall include:
10 (A) the worker's name;
11 (B) the worker's address;
12 (C) the worker's telephone number, if available;
13 (D) the worker's social security number;
14 (E) the worker's classification or
15 classifications;
16 (F) the worker's gross and net wages paid in each
17 pay period;
18 (G) the worker's number of hours worked each day;
19 (H) the worker's starting and ending times of work
20 each day;
21 (I) the worker's hourly wage rate; and
22 (J) the worker's hourly overtime wage rate;
23 (2) no later than the 15th day of each calendar month,
24 provide a certified payroll for the immediately preceding
25 month to the taxpayer in charge of the High Impact
26 Business construction jobs project; within 5 business days

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1 after receiving the certified payroll, the taxpayer shall
2 file the certified payroll with the Department of Labor
3 and the Department of Commerce and Economic Opportunity; a
4 certified payroll must be filed for only those calendar
5 months during which construction on a High Impact Business
6 construction jobs project has occurred; the certified
7 payroll shall consist of a complete copy of the records
8 identified in paragraph (1) of this subsection (j), but
9 may exclude the starting and ending times of work each
10 day; the certified payroll shall be accompanied by a
11 statement signed by the contractor or subcontractor or an
12 officer, employee, or agent of the contractor or
13 subcontractor which avers that:
14 (A) he or she has examined the certified payroll
15 records required to be submitted by the Act and such
16 records are true and accurate; and
17 (B) the contractor or subcontractor is aware that
18 filing a certified payroll that he or she knows to be
19 false is a Class A misdemeanor.
20 A general contractor is not prohibited from relying on a
21certified payroll of a lower-tier subcontractor, provided the
22general contractor does not knowingly rely upon a
23subcontractor's false certification.
24 Any contractor or subcontractor subject to this
25subsection, and any officer, employee, or agent of such
26contractor or subcontractor whose duty as an officer,

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1employee, or agent it is to file a certified payroll under this
2subsection, who willfully fails to file such a certified
3payroll on or before the date such certified payroll is
4required by this paragraph to be filed and any person who
5willfully files a false certified payroll that is false as to
6any material fact is in violation of this Act and guilty of a
7Class A misdemeanor.
8 The taxpayer in charge of the project shall keep the
9records submitted in accordance with this subsection on or
10after June 5, 2021 (the effective date of Public Act 101-9)
11this amendatory Act of the 101st General Assembly for a period
12of 5 years from the date of the last payment for work on a
13contract or subcontract for the High Impact Business
14construction jobs project.
15 The records submitted in accordance with this subsection
16shall be considered public records, except an employee's
17address, telephone number, and social security number, and
18made available in accordance with the Freedom of Information
19Act. The Department of Labor shall accept any reasonable
20submissions by the contractor that meet the requirements of
21this subsection (j) and shall share the information with the
22Department in order to comply with the awarding of a High
23Impact Business construction jobs credit. A contractor,
24subcontractor, or public body may retain records required
25under this Section in paper or electronic format.
26 (k) Upon 7 business days' notice, each contractor and

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1subcontractor shall make available for inspection and copying
2at a location within this State during reasonable hours, the
3records identified in this subsection (j) to the taxpayer in
4charge of the High Impact Business construction jobs project,
5its officers and agents, the Director of the Department of
6Labor and his or her deputies and agents, and to federal,
7State, or local law enforcement agencies and prosecutors.
8(Source: P.A. 101-9, eff. 6-5-19; revised 7-12-19.)
9 Section 15. The Illinois Power Agency Act is amended by
10changing Sections 1-10, 1-56, and 1-75 as follows:
11 (20 ILCS 3855/1-10)
12 Sec. 1-10. Definitions.
13 "Agency" means the Illinois Power Agency.
14 "Agency loan agreement" means any agreement pursuant to
15which the Illinois Finance Authority agrees to loan the
16proceeds of revenue bonds issued with respect to a project to
17the Agency upon terms providing for loan repayment
18installments at least sufficient to pay when due all principal
19of, interest and premium, if any, on those revenue bonds, and
20providing for maintenance, insurance, and other matters in
21respect of the project.
22 "Authority" means the Illinois Finance Authority.
23 "Brownfield site photovoltaic project" means photovoltaics
24that are:

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1 (1) interconnected to an electric utility as defined
2 in this Section, a municipal utility as defined in this
3 Section, a public utility as defined in Section 3-105 of
4 the Public Utilities Act, or an electric cooperative, as
5 defined in Section 3-119 of the Public Utilities Act; and
6 (2) located at a site that is regulated by any of the
7 following entities under the following programs:
8 (A) the United States Environmental Protection
9 Agency under the federal Comprehensive Environmental
10 Response, Compensation, and Liability Act of 1980, as
11 amended;
12 (B) the United States Environmental Protection
13 Agency under the Corrective Action Program of the
14 federal Resource Conservation and Recovery Act, as
15 amended;
16 (C) the Illinois Environmental Protection Agency
17 under the Illinois Site Remediation Program; or
18 (D) the Illinois Environmental Protection Agency
19 under the Illinois Solid Waste Program.
20 "Clean coal facility" means an electric generating
21facility that uses primarily coal as a feedstock and that
22captures and sequesters carbon dioxide emissions at the
23following levels: at least 50% of the total carbon dioxide
24emissions that the facility would otherwise emit if, at the
25time construction commences, the facility is scheduled to
26commence operation before 2016, at least 70% of the total

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1carbon dioxide emissions that the facility would otherwise
2emit if, at the time construction commences, the facility is
3scheduled to commence operation during 2016 or 2017, and at
4least 90% of the total carbon dioxide emissions that the
5facility would otherwise emit if, at the time construction
6commences, the facility is scheduled to commence operation
7after 2017. The power block of the clean coal facility shall
8not exceed allowable emission rates for sulfur dioxide,
9nitrogen oxides, carbon monoxide, particulates and mercury for
10a natural gas-fired combined-cycle facility the same size as
11and in the same location as the clean coal facility at the time
12the clean coal facility obtains an approved air permit. All
13coal used by a clean coal facility shall have high volatile
14bituminous rank and greater than 1.7 pounds of sulfur per
15million btu content, unless the clean coal facility does not
16use gasification technology and was operating as a
17conventional coal-fired electric generating facility on June
181, 2009 (the effective date of Public Act 95-1027).
19 "Clean coal SNG brownfield facility" means a facility that
20(1) has commenced construction by July 1, 2015 on an urban
21brownfield site in a municipality with at least 1,000,000
22residents; (2) uses a gasification process to produce
23substitute natural gas; (3) uses coal as at least 50% of the
24total feedstock over the term of any sourcing agreement with a
25utility and the remainder of the feedstock may be either
26petroleum coke or coal, with all such coal having a high

HB2640- 22 -LRB102 13765 SPS 19115 b
1bituminous rank and greater than 1.7 pounds of sulfur per
2million Btu content unless the facility reasonably determines
3that it is necessary to use additional petroleum coke to
4deliver additional consumer savings, in which case the
5facility shall use coal for at least 35% of the total feedstock
6over the term of any sourcing agreement; and (4) captures and
7sequesters at least 85% of the total carbon dioxide emissions
8that the facility would otherwise emit.
9 "Clean coal SNG facility" means a facility that uses a
10gasification process to produce substitute natural gas, that
11sequesters at least 90% of the total carbon dioxide emissions
12that the facility would otherwise emit, that uses at least 90%
13coal as a feedstock, with all such coal having a high
14bituminous rank and greater than 1.7 pounds of sulfur per
15million btu content, and that has a valid and effective permit
16to construct emission sources and air pollution control
17equipment and approval with respect to the federal regulations
18for Prevention of Significant Deterioration of Air Quality
19(PSD) for the plant pursuant to the federal Clean Air Act;
20provided, however, a clean coal SNG brownfield facility shall
21not be a clean coal SNG facility.
22 "Commission" means the Illinois Commerce Commission.
23 "Community renewable generation project" means an electric
24generating facility that:
25 (1) is powered by wind, solar thermal energy,
26 photovoltaic cells or panels, biodiesel, crops and

HB2640- 23 -LRB102 13765 SPS 19115 b
1 untreated and unadulterated organic waste biomass, tree
2 waste, and hydropower that does not involve new
3 construction or significant expansion of hydropower dams;
4 (2) is interconnected at the distribution system level
5 of an electric utility as defined in this Section, a
6 municipal utility as defined in this Section that owns or
7 operates electric distribution facilities, a public
8 utility as defined in Section 3-105 of the Public
9 Utilities Act, or an electric cooperative, as defined in
10 Section 3-119 of the Public Utilities Act;
11 (3) credits the value of electricity generated by the
12 facility to the subscribers of the facility; and
13 (4) is limited in nameplate capacity to less than or
14 equal to 2,000 kilowatts.
15 "Costs incurred in connection with the development and
16construction of a facility" means:
17 (1) the cost of acquisition of all real property,
18 fixtures, and improvements in connection therewith and
19 equipment, personal property, and other property, rights,
20 and easements acquired that are deemed necessary for the
21 operation and maintenance of the facility;
22 (2) financing costs with respect to bonds, notes, and
23 other evidences of indebtedness of the Agency;
24 (3) all origination, commitment, utilization,
25 facility, placement, underwriting, syndication, credit
26 enhancement, and rating agency fees;

HB2640- 24 -LRB102 13765 SPS 19115 b
1 (4) engineering, design, procurement, consulting,
2 legal, accounting, title insurance, survey, appraisal,
3 escrow, trustee, collateral agency, interest rate hedging,
4 interest rate swap, capitalized interest, contingency, as
5 required by lenders, and other financing costs, and other
6 expenses for professional services; and
7 (5) the costs of plans, specifications, site study and
8 investigation, installation, surveys, other Agency costs
9 and estimates of costs, and other expenses necessary or
10 incidental to determining the feasibility of any project,
11 together with such other expenses as may be necessary or
12 incidental to the financing, insuring, acquisition, and
13 construction of a specific project and starting up,
14 commissioning, and placing that project in operation.
15 "Delivery services" has the same definition as found in
16Section 16-102 of the Public Utilities Act.
17 "Delivery year" means the consecutive 12-month period
18beginning June 1 of a given year and ending May 31 of the
19following year.
20 "Department" means the Department of Commerce and Economic
21Opportunity.
22 "Director" means the Director of the Illinois Power
23Agency.
24 "Demand-response" means measures that decrease peak
25electricity demand or shift demand from peak to off-peak
26periods.

HB2640- 25 -LRB102 13765 SPS 19115 b
1 "Distributed renewable energy generation device" means a
2device that is:
3 (1) powered by wind, solar thermal energy,
4 photovoltaic cells or panels, biodiesel, crops and
5 untreated and unadulterated organic waste biomass, tree
6 waste, and hydropower that does not involve new
7 construction or significant expansion of hydropower dams;
8 (2) interconnected at the distribution system level of
9 either an electric utility as defined in this Section, a
10 municipal utility as defined in this Section that owns or
11 operates electric distribution facilities, or a rural
12 electric cooperative as defined in Section 3-119 of the
13 Public Utilities Act;
14 (3) located on the customer side of the customer's
15 electric meter and is primarily used to offset that
16 customer's electricity load; and
17 (4) limited in nameplate capacity to less than or
18 equal to 2,000 kilowatts.
19 "Energy efficiency" means measures that reduce the amount
20of electricity or natural gas consumed in order to achieve a
21given end use. "Energy efficiency" includes voltage
22optimization measures that optimize the voltage at points on
23the electric distribution voltage system and thereby reduce
24electricity consumption by electric customers' end use
25devices. "Energy efficiency" also includes measures that
26reduce the total Btus of electricity, natural gas, and other

HB2640- 26 -LRB102 13765 SPS 19115 b
1fuels needed to meet the end use or uses.
2 "Electric utility" has the same definition as found in
3Section 16-102 of the Public Utilities Act.
4 "Facility" means an electric generating unit or a
5co-generating unit that produces electricity along with
6related equipment necessary to connect the facility to an
7electric transmission or distribution system.
8 "Governmental aggregator" means one or more units of local
9government that individually or collectively procure
10electricity to serve residential retail electrical loads
11located within its or their jurisdiction.
12 "Index price" means the monthly average load-weighted
13day-ahead price at the ComEd or Ameren Hub.
14 "Local government" means a unit of local government as
15defined in Section 1 of Article VII of the Illinois
16Constitution.
17 "Municipality" means a city, village, or incorporated
18town.
19 "Municipal utility" means a public utility owned and
20operated by any subdivision or municipal corporation of this
21State.
22 "Nameplate capacity" means the aggregate inverter
23nameplate capacity in kilowatts AC.
24 "Offer strike price" means the price for a renewable
25energy credit from a new utility-scale wind project or a
26utility-scale solar project resulting from a new utility-scale

HB2640- 27 -LRB102 13765 SPS 19115 b
1wind or solar competitive procurement.
2 "Person" means any natural person, firm, partnership,
3corporation, either domestic or foreign, company, association,
4limited liability company, joint stock company, or association
5and includes any trustee, receiver, assignee, or personal
6representative thereof.
7 "Project" means the planning, bidding, and construction of
8a facility.
9 "Public utility" has the same definition as found in
10Section 3-105 of the Public Utilities Act.
11 "Real property" means any interest in land together with
12all structures, fixtures, and improvements thereon, including
13lands under water and riparian rights, any easements,
14covenants, licenses, leases, rights-of-way, uses, and other
15interests, together with any liens, judgments, mortgages, or
16other claims or security interests related to real property.
17 "Renewable energy credit" means a tradable credit that
18represents the environmental attributes of one megawatt hour
19of energy produced from a renewable energy resource.
20 "Renewable energy resources" includes energy and its
21associated renewable energy credit or renewable energy credits
22from wind, solar thermal energy, photovoltaic cells and
23panels, biodiesel, anaerobic digestion, crops and untreated
24and unadulterated organic waste biomass, tree waste, and
25hydropower that does not involve new construction or
26significant expansion of hydropower dams. For purposes of this

HB2640- 28 -LRB102 13765 SPS 19115 b
1Act, landfill gas produced in the State is considered a
2renewable energy resource. "Renewable energy resources" does
3not include the incineration or burning of tires, garbage,
4general household, institutional, and commercial waste,
5industrial lunchroom or office waste, landscape waste other
6than tree waste, railroad crossties, utility poles, or
7construction or demolition debris, other than untreated and
8unadulterated waste wood.
9 "Retail customer" has the same definition as found in
10Section 16-102 of the Public Utilities Act.
11 "Revenue bond" means any bond, note, or other evidence of
12indebtedness issued by the Authority, the principal and
13interest of which is payable solely from revenues or income
14derived from any project or activity of the Agency.
15 "Sequester" means permanent storage of carbon dioxide by
16injecting it into a saline aquifer, a depleted gas reservoir,
17or an oil reservoir, directly or through an enhanced oil
18recovery process that may involve intermediate storage,
19regardless of whether these activities are conducted by a
20clean coal facility, a clean coal SNG facility, a clean coal
21SNG brownfield facility, or a party with which a clean coal
22facility, clean coal SNG facility, or clean coal SNG
23brownfield facility has contracted for such purposes.
24 "Service area" has the same definition as found in Section
2516-102 of the Public Utilities Act.
26 "Sourcing agreement" means (i) in the case of an electric

HB2640- 29 -LRB102 13765 SPS 19115 b
1utility, an agreement between the owner of a clean coal
2facility and such electric utility, which agreement shall have
3terms and conditions meeting the requirements of paragraph (3)
4of subsection (d) of Section 1-75, (ii) in the case of an
5alternative retail electric supplier, an agreement between the
6owner of a clean coal facility and such alternative retail
7electric supplier, which agreement shall have terms and
8conditions meeting the requirements of Section 16-115(d)(5) of
9the Public Utilities Act, and (iii) in case of a gas utility,
10an agreement between the owner of a clean coal SNG brownfield
11facility and the gas utility, which agreement shall have the
12terms and conditions meeting the requirements of subsection
13(h-1) of Section 9-220 of the Public Utilities Act.
14 "Subscriber" means a person who (i) takes delivery service
15from an electric utility, and (ii) has a subscription of no
16less than 200 watts to a community renewable generation
17project that is located in the electric utility's service
18area. No subscriber's subscriptions may total more than 40% of
19the nameplate capacity of an individual community renewable
20generation project. Entities that are affiliated by virtue of
21a common parent shall not represent multiple subscriptions
22that total more than 40% of the nameplate capacity of an
23individual community renewable generation project.
24 "Subscription" means an interest in a community renewable
25generation project expressed in kilowatts, which is sized
26primarily to offset part or all of the subscriber's

HB2640- 30 -LRB102 13765 SPS 19115 b
1electricity usage.
2 "Substitute natural gas" or "SNG" means a gas manufactured
3by gasification of hydrocarbon feedstock, which is
4substantially interchangeable in use and distribution with
5conventional natural gas.
6 "Total resource cost test" or "TRC test" means a standard
7that is met if, for an investment in energy efficiency or
8demand-response measures, the benefit-cost ratio is greater
9than one. The benefit-cost ratio is the ratio of the net
10present value of the total benefits of the program to the net
11present value of the total costs as calculated over the
12lifetime of the measures. A total resource cost test compares
13the sum of avoided electric utility costs, representing the
14benefits that accrue to the system and the participant in the
15delivery of those efficiency measures and including avoided
16costs associated with reduced use of natural gas or other
17fuels, avoided costs associated with reduced water
18consumption, and avoided costs associated with reduced
19operation and maintenance costs, as well as other quantifiable
20societal benefits, to the sum of all incremental costs of
21end-use measures that are implemented due to the program
22(including both utility and participant contributions), plus
23costs to administer, deliver, and evaluate each demand-side
24program, to quantify the net savings obtained by substituting
25the demand-side program for supply resources. In calculating
26avoided costs of power and energy that an electric utility

HB2640- 31 -LRB102 13765 SPS 19115 b
1would otherwise have had to acquire, reasonable estimates
2shall be included of financial costs likely to be imposed by
3future regulations and legislation on emissions of greenhouse
4gases. In discounting future societal costs and benefits for
5the purpose of calculating net present values, a societal
6discount rate based on actual, long-term Treasury bond yields
7should be used. Notwithstanding anything to the contrary, the
8TRC test shall not include or take into account a calculation
9of market price suppression effects or demand reduction
10induced price effects.
11 "Utility-scale solar project" means an electric generating
12facility that:
13 (1) generates electricity using photovoltaic cells;
14 and
15 (2) has a nameplate capacity that is greater than
16 2,000 kilowatts.
17 "Utility-scale wind project" means an electric generating
18facility that:
19 (1) generates electricity using wind; and
20 (2) has a nameplate capacity that is greater than
21 2,000 kilowatts.
22 "Variable renewable energy credit" means a renewable
23energy credit which is the difference between the offer strike
24price and the index price.
25 "Zero emission credit" means a tradable credit that
26represents the environmental attributes of one megawatt hour

HB2640- 32 -LRB102 13765 SPS 19115 b
1of energy produced from a zero emission facility.
2 "Zero emission facility" means a facility that: (1) is
3fueled by nuclear power; and (2) is interconnected with PJM
4Interconnection, LLC or the Midcontinent Independent System
5Operator, Inc., or their successors.
6(Source: P.A. 98-90, eff. 7-15-13; 99-906, eff. 6-1-17.)
7 (20 ILCS 3855/1-56)
8 Sec. 1-56. Illinois Power Agency Renewable Energy
9Resources Fund; Illinois Solar for All Program.
10 (a) The Illinois Power Agency Renewable Energy Resources
11Fund is created as a special fund in the State treasury.
12 (b) The Illinois Power Agency Renewable Energy Resources
13Fund shall be administered by the Agency as described in this
14subsection (b), provided that the changes to this subsection
15(b) made by this amendatory Act of the 99th General Assembly
16shall not interfere with existing contracts under this
17Section.
18 (1) The Illinois Power Agency Renewable Energy
19 Resources Fund shall be used to purchase renewable energy
20 credits according to any approved procurement plan
21 developed by the Agency prior to June 1, 2017.
22 (2) The Illinois Power Agency Renewable Energy
23 Resources Fund shall also be used to create the Illinois
24 Solar for All Program, which shall include incentives for
25 low-income distributed generation and community solar

HB2640- 33 -LRB102 13765 SPS 19115 b
1 projects, and other associated approved expenditures. The
2 objectives of the Illinois Solar for All Program are to
3 bring photovoltaics to low-income communities in this
4 State in a manner that maximizes the development of new
5 photovoltaic generating facilities, to create a long-term,
6 low-income solar marketplace throughout this State, to
7 integrate, through interaction with stakeholders, with
8 existing energy efficiency initiatives, and to minimize
9 administrative costs. The Agency shall include a
10 description of its proposed approach to the design,
11 administration, implementation and evaluation of the
12 Illinois Solar for All Program, as part of the long-term
13 renewable resources procurement plan authorized by
14 subsection (c) of Section 1-75 of this Act, and the
15 program shall be designed to grow the low-income solar
16 market. The Agency or utility, as applicable, shall
17 purchase renewable energy credits from the (i)
18 photovoltaic distributed renewable energy generation
19 projects and (ii) community solar projects that are
20 procured under procurement processes authorized by the
21 long-term renewable resources procurement plans approved
22 by the Commission.
23 The Illinois Solar for All Program shall include the
24 program offerings described in subparagraphs (A) through
25 (D) of this paragraph (2), which the Agency shall
26 implement through contracts with third-party providers

HB2640- 34 -LRB102 13765 SPS 19115 b
1 and, subject to appropriation, pay the approximate amounts
2 identified using monies available in the Illinois Power
3 Agency Renewable Energy Resources Fund. Each contract that
4 provides for the installation of solar facilities shall
5 provide that the solar facilities will produce energy and
6 economic benefits, at a level determined by the Agency to
7 be reasonable, for the participating low income customers.
8 The monies available in the Illinois Power Agency
9 Renewable Energy Resources Fund and not otherwise
10 committed to contracts executed under subsection (i) of
11 this Section shall be allocated among the programs
12 described in this paragraph (2), as follows: 22.5% of
13 these funds shall be allocated to programs described in
14 subparagraph (A) of this paragraph (2), 37.5% of these
15 funds shall be allocated to programs described in
16 subparagraph (B) of this paragraph (2), 15% of these funds
17 shall be allocated to programs described in subparagraph
18 (C) of this paragraph (2), and 25% of these funds, but in
19 no event more than $50,000,000, shall be allocated to
20 programs described in subparagraph (D) of this paragraph
21 (2). The allocation of funds among subparagraphs (A), (B),
22 or (C) of this paragraph (2) may be changed if the Agency
23 or administrator, through delegated authority, determines
24 incentives in subparagraphs (A), (B), or (C) of this
25 paragraph (2) have not been adequately subscribed to fully
26 utilize the Illinois Power Agency Renewable Energy

HB2640- 35 -LRB102 13765 SPS 19115 b
1 Resources Fund. The determination shall include input
2 through a stakeholder process. The program offerings
3 described in subparagraphs (A) through (D) of this
4 paragraph (2) shall also be implemented through contracts
5 funded from such additional amounts as are allocated to
6 one or more of the programs in the long-term renewable
7 resources procurement plans as specified in subsection (c)
8 of Section 1-75 of this Act and subparagraph (O) of
9 paragraph (1) of such subsection (c).
10 Contracts that will be paid with funds in the Illinois
11 Power Agency Renewable Energy Resources Fund shall be
12 executed by the Agency. Contracts that will be paid with
13 funds collected by an electric utility shall be executed
14 by the electric utility.
15 Contracts under the Illinois Solar for All Program
16 shall include an approach, as set forth in the long-term
17 renewable resources procurement plans, to ensure the
18 wholesale market value of the energy is credited to
19 participating low-income customers or organizations and to
20 ensure tangible economic benefits flow directly to program
21 participants, except in the case of low-income
22 multi-family housing where the low-income customer does
23 not directly pay for energy. Priority shall be given to
24 projects that demonstrate meaningful involvement of
25 low-income community members in designing the initial
26 proposals. Acceptable proposals to implement projects must

HB2640- 36 -LRB102 13765 SPS 19115 b
1 demonstrate the applicant's ability to conduct initial
2 community outreach, education, and recruitment of
3 low-income participants in the community. Projects must
4 include job training opportunities if available, and shall
5 endeavor to coordinate with the job training programs
6 described in paragraph (1) of subsection (a) of Section
7 16-108.12 of the Public Utilities Act.
8 (A) Low-income distributed generation incentive.
9 This program will provide incentives to low-income
10 customers, either directly or through solar providers,
11 to increase the participation of low-income households
12 in photovoltaic on-site distributed generation.
13 Companies participating in this program that install
14 solar panels shall commit to hiring job trainees for a
15 portion of their low-income installations, and an
16 administrator shall facilitate partnering the
17 companies that install solar panels with entities that
18 provide solar panel installation job training. It is a
19 goal of this program that a minimum of 25% of the
20 incentives for this program be allocated to projects
21 located within environmental justice communities.
22 Contracts entered into under this paragraph may be
23 entered into with an entity that will develop and
24 administer the program and shall also include
25 contracts for renewable energy credits from the
26 photovoltaic distributed generation that is the

HB2640- 37 -LRB102 13765 SPS 19115 b
1 subject of the program, as set forth in the long-term
2 renewable resources procurement plan.
3 (B) Low-Income Community Solar Project Initiative.
4 Incentives shall be offered to low-income customers,
5 either directly or through developers, to increase the
6 participation of low-income subscribers of community
7 solar projects. The developer of each project shall
8 identify its partnership with community stakeholders
9 regarding the location, development, and participation
10 in the project, provided that nothing shall preclude a
11 project from including an anchor tenant that does not
12 qualify as low-income. Incentives should also be
13 offered to community solar projects that are 100%
14 low-income subscriber owned, which includes low-income
15 households, not-for-profit organizations, and
16 affordable housing owners. It is a goal of this
17 program that a minimum of 25% of the incentives for
18 this program be allocated to community photovoltaic
19 projects in environmental justice communities.
20 Contracts entered into under this paragraph may be
21 entered into with developers and shall also include
22 contracts for renewable energy credits related to the
23 program.
24 (C) Incentives for non-profits and public
25 facilities. Under this program funds shall be used to
26 support on-site photovoltaic distributed renewable

HB2640- 38 -LRB102 13765 SPS 19115 b
1 energy generation devices to serve the load associated
2 with not-for-profit customers and to support
3 photovoltaic distributed renewable energy generation
4 that uses photovoltaic technology to serve the load
5 associated with public sector customers taking service
6 at public buildings. It is a goal of this program that
7 at least 25% of the incentives for this program be
8 allocated to projects located in environmental justice
9 communities. Contracts entered into under this
10 paragraph may be entered into with an entity that will
11 develop and administer the program or with developers
12 and shall also include contracts for renewable energy
13 credits related to the program.
14 (D) Low-Income Community Solar Pilot Projects.
15 Under this program, persons, including, but not
16 limited to, electric utilities, shall propose pilot
17 community solar projects. Community solar projects
18 proposed under this subparagraph (D) may exceed 2,000
19 kilowatts in nameplate capacity, but the amount paid
20 per project under this program may not exceed
21 $20,000,000. Pilot projects must result in economic
22 benefits for the members of the community in which the
23 project will be located. The proposed pilot project
24 must include a partnership with at least one
25 community-based organization. Approved pilot projects
26 shall be competitively bid by the Agency, subject to

HB2640- 39 -LRB102 13765 SPS 19115 b
1 fair and equitable guidelines developed by the Agency.
2 Funding available under this subparagraph (D) may not
3 be distributed solely to a utility, and at least some
4 funds under this subparagraph (D) must include a
5 project partnership that includes community ownership
6 by the project subscribers. Contracts entered into
7 under this paragraph may be entered into with an
8 entity that will develop and administer the program or
9 with developers and shall also include contracts for
10 renewable energy credits related to the program. A
11 project proposed by a utility that is implemented
12 under this subparagraph (D) shall not be included in
13 the utility's ratebase.
14 The requirement that a qualified person, as defined in
15 paragraph (1) of subsection (i) of this Section, install
16 photovoltaic devices does not apply to the Illinois Solar
17 for All Program described in this subsection (b).
18 (3) Costs associated with the Illinois Solar for All
19 Program and its components described in paragraph (2) of
20 this subsection (b), including, but not limited to, costs
21 associated with procuring experts, consultants, and the
22 program administrator referenced in this subsection (b)
23 and related incremental costs, and costs related to the
24 evaluation of the Illinois Solar for All Program, may be
25 paid for using monies in the Illinois Power Agency
26 Renewable Energy Resources Fund, but the Agency or program

HB2640- 40 -LRB102 13765 SPS 19115 b
1 administrator shall strive to minimize costs in the
2 implementation of the program. The Agency shall purchase
3 renewable energy credits from generation that is the
4 subject of a contract under subparagraphs (A) through (D)
5 of this paragraph (2) of this subsection (b), and may pay
6 for such renewable energy credits through an upfront
7 payment per installed kilowatt of nameplate capacity paid
8 once the device is interconnected at the distribution
9 system level of the utility and is energized. The payment
10 shall be in exchange for an assignment of all renewable
11 energy credits generated by the system during the first 15
12 years of operation and shall be structured to overcome
13 barriers to participation in the solar market by the
14 low-income community. The incentives provided for in this
15 Section may be implemented through the pricing of
16 renewable energy credits where the prices paid for the
17 credits are higher than the prices from programs offered
18 under subsection (c) of Section 1-75 of this Act to
19 account for the incentives. If the prices paid for
20 renewable energy credits under this Section are higher
21 than the prices paid from programs offered under
22 subsection (c) of Section 1-75 of this Act, then the
23 average difference in price for a comparable product shall
24 not count toward the limitation or reduction found in
25 subparagraph (E) of paragraph (1) of subsection (c) of
26 Section 1-75 of this Act. The Agency shall ensure

HB2640- 41 -LRB102 13765 SPS 19115 b
1 collaboration with community agencies, and allocate up to
2 5% of the funds available under the Illinois Solar for All
3 Program to community-based groups to assist in grassroots
4 education efforts related to the Illinois Solar for All
5 Program. The Agency shall retire any renewable energy
6 credits purchased from this program and the credits shall
7 count towards the obligation under subsection (c) of
8 Section 1-75 of this Act for the electric utility to which
9 the project is interconnected.
10 (4) The Agency shall, consistent with the requirements
11 of this subsection (b), propose the Illinois Solar for All
12 Program terms, conditions, and requirements, including the
13 prices to be paid for renewable energy credits, and which
14 prices may be determined through a formula, through the
15 development, review, and approval of the Agency's
16 long-term renewable resources procurement plan described
17 in subsection (c) of Section 1-75 of this Act and Section
18 16-111.5 of the Public Utilities Act. In the course of the
19 Commission proceeding initiated to review and approve the
20 plan, including the Illinois Solar for All Program
21 proposed by the Agency, a party may propose an additional
22 low-income solar or solar incentive program, or
23 modifications to the programs proposed by the Agency, and
24 the Commission may approve an additional program, or
25 modifications to the Agency's proposed program, if the
26 additional or modified program more effectively maximizes

HB2640- 42 -LRB102 13765 SPS 19115 b
1 the benefits to low-income customers after taking into
2 account all relevant factors, including, but not limited
3 to, the extent to which a competitive market for
4 low-income solar has developed. Following the Commission's
5 approval of the Illinois Solar for All Program, the Agency
6 or a party may propose adjustments to the program terms,
7 conditions, and requirements, including the price offered
8 to new systems, to ensure the long-term viability and
9 success of the program. The Commission shall review and
10 approve any modifications to the program through the plan
11 revision process described in Section 16-111.5 of the
12 Public Utilities Act.
13 (5) The Agency shall issue a request for
14 qualifications for a third-party program administrator or
15 administrators to administer all or a portion of the
16 Illinois Solar for All Program. The third-party program
17 administrator shall be chosen through a competitive bid
18 process based on selection criteria and requirements
19 developed by the Agency, including, but not limited to,
20 experience in administering low-income energy programs and
21 overseeing statewide clean energy or energy efficiency
22 services. If the Agency retains a program administrator or
23 administrators to implement all or a portion of the
24 Illinois Solar for All Program, each administrator shall
25 periodically submit reports to the Agency and Commission
26 for each program that it administers, at appropriate

HB2640- 43 -LRB102 13765 SPS 19115 b
1 intervals to be identified by the Agency in its long-term
2 renewable resources procurement plan, provided that the
3 reporting interval is at least quarterly.
4 (6) The long-term renewable resources procurement plan
5 shall also provide for an independent evaluation of the
6 Illinois Solar for All Program. At least every 2 years,
7 the Agency shall select an independent evaluator to review
8 and report on the Illinois Solar for All Program and the
9 performance of the third-party program administrator of
10 the Illinois Solar for All Program. The evaluation shall
11 be based on objective criteria developed through a public
12 stakeholder process. The process shall include feedback
13 and participation from Illinois Solar for All Program
14 stakeholders, including participants and organizations in
15 environmental justice and historically underserved
16 communities. The report shall include a summary of the
17 evaluation of the Illinois Solar for All Program based on
18 the stakeholder developed objective criteria. The report
19 shall include the number of projects installed; the total
20 installed capacity in kilowatts; the average cost per
21 kilowatt of installed capacity to the extent reasonably
22 obtainable by the Agency; the number of jobs or job
23 opportunities created; economic, social, and environmental
24 benefits created; and the total administrative costs
25 expended by the Agency and program administrator to
26 implement and evaluate the program. The report shall be

HB2640- 44 -LRB102 13765 SPS 19115 b
1 delivered to the Commission and posted on the Agency's
2 website, and shall be used, as needed, to revise the
3 Illinois Solar for All Program. The Commission shall also
4 consider the results of the evaluation as part of its
5 review of the long-term renewable resources procurement
6 plan under subsection (c) of Section 1-75 of this Act.
7 (7) If additional funding for the programs described
8 in this subsection (b) is available under subsection (k)
9 of Section 16-108 of the Public Utilities Act, then the
10 Agency shall submit a procurement plan to the Commission
11 no later than September 1, 2018, that proposes how the
12 Agency will procure programs on behalf of the applicable
13 utility. After notice and hearing, the Commission shall
14 approve, or approve with modification, the plan no later
15 than November 1, 2018.
16 As used in this subsection (b), "low-income households"
17means persons and families whose income does not exceed 80% of
18area median income, adjusted for family size and revised every
195 years.
20 For the purposes of this subsection (b), the Agency shall
21define "environmental justice community" as part of long-term
22renewable resources procurement plan development, to ensure,
23to the extent practicable, compatibility with other agencies'
24definitions and may, for guidance, look to the definitions
25used by federal, state, or local governments.
26 (b-5) After the receipt of all payments required by

HB2640- 45 -LRB102 13765 SPS 19115 b
1Section 16-115D of the Public Utilities Act, no additional
2funds shall be deposited into the Illinois Power Agency
3Renewable Energy Resources Fund unless directed by order of
4the Commission.
5 (b-10) After the receipt of all payments required by
6Section 16-115D of the Public Utilities Act and payment in
7full of all contracts executed by the Agency under subsections
8(b) and (i) of this Section, if the balance of the Illinois
9Power Agency Renewable Energy Resources Fund is under $5,000,
10then the Fund shall be inoperative and any remaining funds and
11any funds submitted to the Fund after that date, shall be
12transferred to the Supplemental Low-Income Energy Assistance
13Fund for use in the Low-Income Home Energy Assistance Program,
14as authorized by the Energy Assistance Act.
15 (c) (Blank).
16 (d) (Blank).
17 (e) All renewable energy credits procured using monies
18from the Illinois Power Agency Renewable Energy Resources Fund
19shall be permanently retired.
20 (f) The selection of one or more third-party program
21managers or administrators, the selection of the independent
22evaluator, and the procurement processes described in this
23Section are exempt from the requirements of the Illinois
24Procurement Code, under Section 20-10 of that Code.
25 (g) All disbursements from the Illinois Power Agency
26Renewable Energy Resources Fund shall be made only upon

HB2640- 46 -LRB102 13765 SPS 19115 b
1warrants of the Comptroller drawn upon the Treasurer as
2custodian of the Fund upon vouchers signed by the Director or
3by the person or persons designated by the Director for that
4purpose. The Comptroller is authorized to draw the warrant
5upon vouchers so signed. The Treasurer shall accept all
6warrants so signed and shall be released from liability for
7all payments made on those warrants.
8 (h) The Illinois Power Agency Renewable Energy Resources
9Fund shall not be subject to sweeps, administrative charges,
10or chargebacks, including, but not limited to, those
11authorized under Section 8h of the State Finance Act, that
12would in any way result in the transfer of any funds from this
13Fund to any other fund of this State or in having any such
14funds utilized for any purpose other than the express purposes
15set forth in this Section.
16 (h-5) The Agency may assess fees to each bidder to recover
17the costs incurred in connection with a procurement process
18held under this Section. Fees collected from bidders shall be
19deposited into the Renewable Energy Resources Fund.
20 (i) Supplemental procurement process.
21 (1) Within 90 days after the effective date of this
22 amendatory Act of the 98th General Assembly, the Agency
23 shall develop a one-time supplemental procurement plan
24 limited to the procurement of renewable energy credits, if
25 available, from new or existing photovoltaics, including,
26 but not limited to, distributed photovoltaic generation.

HB2640- 47 -LRB102 13765 SPS 19115 b
1 Nothing in this subsection (i) requires procurement of
2 wind generation through the supplemental procurement.
3 Renewable energy credits procured from new
4 photovoltaics, including, but not limited to, distributed
5 photovoltaic generation, under this subsection (i) must be
6 procured from devices installed by a qualified person. In
7 its supplemental procurement plan, the Agency shall
8 establish contractually enforceable mechanisms for
9 ensuring that the installation of new photovoltaics is
10 performed by a qualified person.
11 For the purposes of this paragraph (1), "qualified
12 person" means a person who performs installations of
13 photovoltaics, including, but not limited to, distributed
14 photovoltaic generation, and who: (A) has completed an
15 apprenticeship as a journeyman electrician from a United
16 States Department of Labor registered electrical
17 apprenticeship and training program and received a
18 certification of satisfactory completion; or (B) does not
19 currently meet the criteria under clause (A) of this
20 paragraph (1), but is enrolled in a United States
21 Department of Labor registered electrical apprenticeship
22 program, provided that the person is directly supervised
23 by a person who meets the criteria under clause (A) of this
24 paragraph (1); or (C) has obtained one of the following
25 credentials in addition to attesting to satisfactory
26 completion of at least 5 years or 8,000 hours of

HB2640- 48 -LRB102 13765 SPS 19115 b
1 documented hands-on electrical experience: (i) a North
2 American Board of Certified Energy Practitioners (NABCEP)
3 Installer Certificate for Solar PV; (ii) an Underwriters
4 Laboratories (UL) PV Systems Installer Certificate; (iii)
5 an Electronics Technicians Association, International
6 (ETAI) Level 3 PV Installer Certificate; or (iv) an
7 Associate in Applied Science degree from an Illinois
8 Community College Board approved community college program
9 in renewable energy or a distributed generation
10 technology.
11 For the purposes of this paragraph (1), "directly
12 supervised" means that there is a qualified person who
13 meets the qualifications under clause (A) of this
14 paragraph (1) and who is available for supervision and
15 consultation regarding the work performed by persons under
16 clause (B) of this paragraph (1), including a final
17 inspection of the installation work that has been directly
18 supervised to ensure safety and conformity with applicable
19 codes.
20 For the purposes of this paragraph (1), "install"
21 means the major activities and actions required to
22 connect, in accordance with applicable building and
23 electrical codes, the conductors, connectors, and all
24 associated fittings, devices, power outlets, or
25 apparatuses mounted at the premises that are directly
26 involved in delivering energy to the premises' electrical

HB2640- 49 -LRB102 13765 SPS 19115 b
1 wiring from the photovoltaics, including, but not limited
2 to, to distributed photovoltaic generation.
3 The renewable energy credits procured pursuant to the
4 supplemental procurement plan shall be procured using up
5 to $30,000,000 from the Illinois Power Agency Renewable
6 Energy Resources Fund. The Agency shall not plan to use
7 funds from the Illinois Power Agency Renewable Energy
8 Resources Fund in excess of the monies on deposit in such
9 fund or projected to be deposited into such fund. The
10 supplemental procurement plan shall ensure adequate,
11 reliable, affordable, efficient, and environmentally
12 sustainable renewable energy resources (including credits)
13 at the lowest total cost over time, taking into account
14 any benefits of price stability.
15 To the extent available, 50% of the renewable energy
16 credits procured from distributed renewable energy
17 generation shall come from devices of less than 25
18 kilowatts in nameplate capacity. Procurement of renewable
19 energy credits from distributed renewable energy
20 generation devices shall be done through multi-year
21 contracts of no less than 5 years. The Agency shall create
22 credit requirements for counterparties. In order to
23 minimize the administrative burden on contracting
24 entities, the Agency shall solicit the use of third
25 parties to aggregate distributed renewable energy. These
26 third parties shall enter into and administer contracts

HB2640- 50 -LRB102 13765 SPS 19115 b
1 with individual distributed renewable energy generation
2 device owners. An individual distributed renewable energy
3 generation device owner shall have the ability to measure
4 the output of his or her distributed renewable energy
5 generation device.
6 In developing the supplemental procurement plan, the
7 Agency shall hold at least one workshop open to the public
8 within 90 days after the effective date of this amendatory
9 Act of the 98th General Assembly and shall consider any
10 comments made by stakeholders or the public. Upon
11 development of the supplemental procurement plan within
12 this 90-day period, copies of the supplemental procurement
13 plan shall be posted and made publicly available on the
14 Agency's and Commission's websites. All interested parties
15 shall have 14 days following the date of posting to
16 provide comment to the Agency on the supplemental
17 procurement plan. All comments submitted to the Agency
18 shall be specific, supported by data or other detailed
19 analyses, and, if objecting to all or a portion of the
20 supplemental procurement plan, accompanied by specific
21 alternative wording or proposals. All comments shall be
22 posted on the Agency's and Commission's websites. Within
23 14 days following the end of the 14-day review period, the
24 Agency shall revise the supplemental procurement plan as
25 necessary based on the comments received and file its
26 revised supplemental procurement plan with the Commission

HB2640- 51 -LRB102 13765 SPS 19115 b
1 for approval.
2 (2) Within 5 days after the filing of the supplemental
3 procurement plan at the Commission, any person objecting
4 to the supplemental procurement plan shall file an
5 objection with the Commission. Within 10 days after the
6 filing, the Commission shall determine whether a hearing
7 is necessary. The Commission shall enter its order
8 confirming or modifying the supplemental procurement plan
9 within 90 days after the filing of the supplemental
10 procurement plan by the Agency.
11 (3) The Commission shall approve the supplemental
12 procurement plan of renewable energy credits to be
13 procured from new or existing photovoltaics, including,
14 but not limited to, distributed photovoltaic generation,
15 if the Commission determines that it will ensure adequate,
16 reliable, affordable, efficient, and environmentally
17 sustainable electric service in the form of renewable
18 energy credits at the lowest total cost over time, taking
19 into account any benefits of price stability.
20 (4) The supplemental procurement process under this
21 subsection (i) shall include each of the following
22 components:
23 (A) Procurement administrator. The Agency may
24 retain a procurement administrator in the manner set
25 forth in item (2) of subsection (a) of Section 1-75 of
26 this Act to conduct the supplemental procurement or

HB2640- 52 -LRB102 13765 SPS 19115 b
1 may elect to use the same procurement administrator
2 administering the Agency's annual procurement under
3 Section 1-75.
4 (B) Procurement monitor. The procurement monitor
5 retained by the Commission pursuant to Section
6 16-111.5 of the Public Utilities Act shall:
7 (i) monitor interactions among the procurement
8 administrator and bidders and suppliers;
9 (ii) monitor and report to the Commission on
10 the progress of the supplemental procurement
11 process;
12 (iii) provide an independent confidential
13 report to the Commission regarding the results of
14 the procurement events;
15 (iv) assess compliance with the procurement
16 plan approved by the Commission for the
17 supplemental procurement process;
18 (v) preserve the confidentiality of supplier
19 and bidding information in a manner consistent
20 with all applicable laws, rules, regulations, and
21 tariffs;
22 (vi) provide expert advice to the Commission
23 and consult with the procurement administrator
24 regarding issues related to procurement process
25 design, rules, protocols, and policy-related
26 matters;

HB2640- 53 -LRB102 13765 SPS 19115 b
1 (vii) consult with the procurement
2 administrator regarding the development and use of
3 benchmark criteria, standard form contracts,
4 credit policies, and bid documents; and
5 (viii) perform, with respect to the
6 supplemental procurement process, any other
7 procurement monitor duties specifically delineated
8 within subsection (i) of this Section.
9 (C) Solicitation, pre-qualification, and
10 registration of bidders. The procurement administrator
11 shall disseminate information to potential bidders to
12 promote a procurement event, notify potential bidders
13 that the procurement administrator may enter into a
14 post-bid price negotiation with bidders that meet the
15 applicable benchmarks, provide supply requirements,
16 and otherwise explain the competitive procurement
17 process. In addition to such other publication as the
18 procurement administrator determines is appropriate,
19 this information shall be posted on the Agency's and
20 the Commission's websites. The procurement
21 administrator shall also administer the
22 prequalification process, including evaluation of
23 credit worthiness, compliance with procurement rules,
24 and agreement to the standard form contract developed
25 pursuant to item (D) of this paragraph (4). The
26 procurement administrator shall then identify and

HB2640- 54 -LRB102 13765 SPS 19115 b
1 register bidders to participate in the procurement
2 event.
3 (D) Standard contract forms and credit terms and
4 instruments. The procurement administrator, in
5 consultation with the Agency, the Commission, and
6 other interested parties and subject to Commission
7 oversight, shall develop and provide standard contract
8 forms for the supplier contracts that meet generally
9 accepted industry practices as well as include any
10 applicable State of Illinois terms and conditions that
11 are required for contracts entered into by an agency
12 of the State of Illinois. Standard credit terms and
13 instruments that meet generally accepted industry
14 practices shall be similarly developed. Contracts for
15 new photovoltaics shall include a provision attesting
16 that the supplier will use a qualified person for the
17 installation of the device pursuant to paragraph (1)
18 of subsection (i) of this Section. The procurement
19 administrator shall make available to the Commission
20 all written comments it receives on the contract
21 forms, credit terms, or instruments. If the
22 procurement administrator cannot reach agreement with
23 the parties as to the contract terms and conditions,
24 the procurement administrator must notify the
25 Commission of any disputed terms and the Commission
26 shall resolve the dispute. The terms of the contracts

HB2640- 55 -LRB102 13765 SPS 19115 b
1 shall not be subject to negotiation by winning
2 bidders, and the bidders must agree to the terms of the
3 contract in advance so that winning bids are selected
4 solely on the basis of price.
5 (E) Requests for proposals; competitive
6 procurement process. The procurement administrator
7 shall design and issue requests for proposals to
8 supply renewable energy credits in accordance with the
9 supplemental procurement plan, as approved by the
10 Commission. The requests for proposals shall set forth
11 a procedure for sealed, binding commitment bidding
12 with pay-as-bid settlement, and provision for
13 selection of bids on the basis of price, provided,
14 however, that no bid shall be accepted if it exceeds
15 the benchmark developed pursuant to item (F) of this
16 paragraph (4).
17 (F) Benchmarks. Benchmarks for each product to be
18 procured shall be developed by the procurement
19 administrator in consultation with Commission staff,
20 the Agency, and the procurement monitor for use in
21 this supplemental procurement.
22 (G) A plan for implementing contingencies in the
23 event of supplier default, Commission rejection of
24 results, or any other cause.
25 (5) Within 2 business days after opening the sealed
26 bids, the procurement administrator shall submit a

HB2640- 56 -LRB102 13765 SPS 19115 b
1 confidential report to the Commission. The report shall
2 contain the results of the bidding for each of the
3 products along with the procurement administrator's
4 recommendation for the acceptance and rejection of bids
5 based on the price benchmark criteria and other factors
6 observed in the process. The procurement monitor also
7 shall submit a confidential report to the Commission
8 within 2 business days after opening the sealed bids. The
9 report shall contain the procurement monitor's assessment
10 of bidder behavior in the process as well as an assessment
11 of the procurement administrator's compliance with the
12 procurement process and rules. The Commission shall review
13 the confidential reports submitted by the procurement
14 administrator and procurement monitor and shall accept or
15 reject the recommendations of the procurement
16 administrator within 2 business days after receipt of the
17 reports.
18 (6) Within 3 business days after the Commission
19 decision approving the results of a procurement event, the
20 Agency shall enter into binding contractual arrangements
21 with the winning suppliers using the standard form
22 contracts.
23 (7) The names of the successful bidders and the
24 average of the winning bid prices for each contract type
25 and for each contract term shall be made available to the
26 public within 2 days after the supplemental procurement

HB2640- 57 -LRB102 13765 SPS 19115 b
1 event. The Commission, the procurement monitor, the
2 procurement administrator, the Agency, and all
3 participants in the procurement process shall maintain the
4 confidentiality of all other supplier and bidding
5 information in a manner consistent with all applicable
6 laws, rules, regulations, and tariffs. Confidential
7 information, including the confidential reports submitted
8 by the procurement administrator and procurement monitor
9 pursuant to this Section, shall not be made publicly
10 available and shall not be discoverable by any party in
11 any proceeding, absent a compelling demonstration of need,
12 nor shall those reports be admissible in any proceeding
13 other than one for law enforcement purposes.
14 (8) The supplemental procurement provided in this
15 subsection (i) shall not be subject to the requirements
16 and limitations of subsections (c) and (d) of this
17 Section.
18 (9) Expenses incurred in connection with the
19 procurement process held pursuant to this Section,
20 including, but not limited to, the cost of developing the
21 supplemental procurement plan, the procurement
22 administrator, procurement monitor, and the cost of the
23 retirement of renewable energy credits purchased pursuant
24 to the supplemental procurement shall be paid for from the
25 Illinois Power Agency Renewable Energy Resources Fund. The
26 Agency shall enter into an interagency agreement with the

HB2640- 58 -LRB102 13765 SPS 19115 b
1 Commission to reimburse the Commission for its costs
2 associated with the procurement monitor for the
3 supplemental procurement process.
4(Source: P.A. 98-672, eff. 6-30-14; 99-906, eff. 6-1-17.)
5 (20 ILCS 3855/1-75)
6 Sec. 1-75. Planning and Procurement Bureau. The Planning
7and Procurement Bureau has the following duties and
8responsibilities:
9 (a) The Planning and Procurement Bureau shall each year,
10beginning in 2008, develop procurement plans and conduct
11competitive procurement processes in accordance with the
12requirements of Section 16-111.5 of the Public Utilities Act
13for the eligible retail customers of electric utilities that
14on December 31, 2005 provided electric service to at least
15100,000 customers in Illinois. Beginning with the delivery
16year commencing on June 1, 2017, the Planning and Procurement
17Bureau shall develop plans and processes for the procurement
18of zero emission credits from zero emission facilities in
19accordance with the requirements of subsection (d-5) of this
20Section. The Planning and Procurement Bureau shall also
21develop procurement plans and conduct competitive procurement
22processes in accordance with the requirements of Section
2316-111.5 of the Public Utilities Act for the eligible retail
24customers of small multi-jurisdictional electric utilities
25that (i) on December 31, 2005 served less than 100,000

HB2640- 59 -LRB102 13765 SPS 19115 b
1customers in Illinois and (ii) request a procurement plan for
2their Illinois jurisdictional load. This Section shall not
3apply to a small multi-jurisdictional utility until such time
4as a small multi-jurisdictional utility requests the Agency to
5prepare a procurement plan for their Illinois jurisdictional
6load. For the purposes of this Section, the term "eligible
7retail customers" has the same definition as found in Section
816-111.5(a) of the Public Utilities Act.
9 Beginning with the plan or plans to be implemented in the
102017 delivery year, the Agency shall no longer include the
11procurement of renewable energy resources in the annual
12procurement plans required by this subsection (a), except as
13provided in subsection (q) of Section 16-111.5 of the Public
14Utilities Act, and shall instead develop a long-term renewable
15resources procurement plan in accordance with subsection (c)
16of this Section and Section 16-111.5 of the Public Utilities
17Act.
18 (1) The Agency shall each year, beginning in 2008, as
19 needed, issue a request for qualifications for experts or
20 expert consulting firms to develop the procurement plans
21 in accordance with Section 16-111.5 of the Public
22 Utilities Act. In order to qualify an expert or expert
23 consulting firm must have:
24 (A) direct previous experience assembling
25 large-scale power supply plans or portfolios for
26 end-use customers;

HB2640- 60 -LRB102 13765 SPS 19115 b
1 (B) an advanced degree in economics, mathematics,
2 engineering, risk management, or a related area of
3 study;
4 (C) 10 years of experience in the electricity
5 sector, including managing supply risk;
6 (D) expertise in wholesale electricity market
7 rules, including those established by the Federal
8 Energy Regulatory Commission and regional transmission
9 organizations;
10 (E) expertise in credit protocols and familiarity
11 with contract protocols;
12 (F) adequate resources to perform and fulfill the
13 required functions and responsibilities; and
14 (G) the absence of a conflict of interest and
15 inappropriate bias for or against potential bidders or
16 the affected electric utilities.
17 (2) The Agency shall each year, as needed, issue a
18 request for qualifications for a procurement administrator
19 to conduct the competitive procurement processes in
20 accordance with Section 16-111.5 of the Public Utilities
21 Act. In order to qualify an expert or expert consulting
22 firm must have:
23 (A) direct previous experience administering a
24 large-scale competitive procurement process;
25 (B) an advanced degree in economics, mathematics,
26 engineering, or a related area of study;

HB2640- 61 -LRB102 13765 SPS 19115 b
1 (C) 10 years of experience in the electricity
2 sector, including risk management experience;
3 (D) expertise in wholesale electricity market
4 rules, including those established by the Federal
5 Energy Regulatory Commission and regional transmission
6 organizations;
7 (E) expertise in credit and contract protocols;
8 (F) adequate resources to perform and fulfill the
9 required functions and responsibilities; and
10 (G) the absence of a conflict of interest and
11 inappropriate bias for or against potential bidders or
12 the affected electric utilities.
13 (3) The Agency shall provide affected utilities and
14 other interested parties with the lists of qualified
15 experts or expert consulting firms identified through the
16 request for qualifications processes that are under
17 consideration to develop the procurement plans and to
18 serve as the procurement administrator. The Agency shall
19 also provide each qualified expert's or expert consulting
20 firm's response to the request for qualifications. All
21 information provided under this subparagraph shall also be
22 provided to the Commission. The Agency may provide by rule
23 for fees associated with supplying the information to
24 utilities and other interested parties. These parties
25 shall, within 5 business days, notify the Agency in
26 writing if they object to any experts or expert consulting

HB2640- 62 -LRB102 13765 SPS 19115 b
1 firms on the lists. Objections shall be based on:
2 (A) failure to satisfy qualification criteria;
3 (B) identification of a conflict of interest; or
4 (C) evidence of inappropriate bias for or against
5 potential bidders or the affected utilities.
6 The Agency shall remove experts or expert consulting
7 firms from the lists within 10 days if there is a
8 reasonable basis for an objection and provide the updated
9 lists to the affected utilities and other interested
10 parties. If the Agency fails to remove an expert or expert
11 consulting firm from a list, an objecting party may seek
12 review by the Commission within 5 days thereafter by
13 filing a petition, and the Commission shall render a
14 ruling on the petition within 10 days. There is no right of
15 appeal of the Commission's ruling.
16 (4) The Agency shall issue requests for proposals to
17 the qualified experts or expert consulting firms to
18 develop a procurement plan for the affected utilities and
19 to serve as procurement administrator.
20 (5) The Agency shall select an expert or expert
21 consulting firm to develop procurement plans based on the
22 proposals submitted and shall award contracts of up to 5
23 years to those selected.
24 (6) The Agency shall select an expert or expert
25 consulting firm, with approval of the Commission, to serve
26 as procurement administrator based on the proposals

HB2640- 63 -LRB102 13765 SPS 19115 b
1 submitted. If the Commission rejects, within 5 days, the
2 Agency's selection, the Agency shall submit another
3 recommendation within 3 days based on the proposals
4 submitted. The Agency shall award a 5-year contract to the
5 expert or expert consulting firm so selected with
6 Commission approval.
7 (b) The experts or expert consulting firms retained by the
8Agency shall, as appropriate, prepare procurement plans, and
9conduct a competitive procurement process as prescribed in
10Section 16-111.5 of the Public Utilities Act, to ensure
11adequate, reliable, affordable, efficient, and environmentally
12sustainable electric service at the lowest total cost over
13time, taking into account any benefits of price stability, for
14eligible retail customers of electric utilities that on
15December 31, 2005 provided electric service to at least
16100,000 customers in the State of Illinois, and for eligible
17Illinois retail customers of small multi-jurisdictional
18electric utilities that (i) on December 31, 2005 served less
19than 100,000 customers in Illinois and (ii) request a
20procurement plan for their Illinois jurisdictional load.
21 (c) Renewable portfolio standard.
22 (1)(A) The Agency shall develop a long-term renewable
23 resources procurement plan that shall include procurement
24 programs and competitive procurement events necessary to
25 meet the goals set forth in this subsection (c). The
26 initial long-term renewable resources procurement plan

HB2640- 64 -LRB102 13765 SPS 19115 b
1 shall be released for comment no later than 160 days after
2 June 1, 2017 (the effective date of Public Act 99-906).
3 The Agency shall review, and may revise on an expedited
4 basis, the long-term renewable resources procurement plan
5 at least every 2 years, which shall be conducted in
6 conjunction with the procurement plan under Section
7 16-111.5 of the Public Utilities Act to the extent
8 practicable to minimize administrative expense. The
9 long-term renewable resources procurement plans shall be
10 subject to review and approval by the Commission under
11 Section 16-111.5 of the Public Utilities Act.
12 (B) Subject to subparagraph (F) of this paragraph (1),
13 the long-term renewable resources procurement plan shall
14 include the goals for procurement of renewable energy
15 credits to meet at least the following overall
16 percentages: 13% by the 2017 delivery year; increasing by
17 at least 1.5% each delivery year thereafter to at least
18 25% by the 2025 delivery year; increasing by at least 2.5%
19 each delivery year thereafter to at least 37.5% by the
20 2030 delivery year; and continuing at no less than 37.5%
21 25% for each delivery year thereafter. In the event of a
22 conflict between these goals and the new wind and new
23 photovoltaic procurement requirements described in items
24 (i) through (iii) of subparagraph (C) of this paragraph
25 (1), the long-term plan shall prioritize compliance with
26 the new wind and new photovoltaic procurement requirements

HB2640- 65 -LRB102 13765 SPS 19115 b
1 described in items (i) through (iii) of subparagraph (C)
2 of this paragraph (1) over the annual percentage targets
3 described in this subparagraph (B).
4 For the delivery year beginning June 1, 2017, the
5 procurement plan shall include cost-effective renewable
6 energy resources equal to at least 13% of each utility's
7 load for eligible retail customers and 13% of the
8 applicable portion of each utility's load for retail
9 customers who are not eligible retail customers, which
10 applicable portion shall equal 50% of the utility's load
11 for retail customers who are not eligible retail customers
12 on February 28, 2017.
13 For the delivery year beginning June 1, 2018, the
14 procurement plan shall include cost-effective renewable
15 energy resources equal to at least 14.5% of each utility's
16 load for eligible retail customers and 14.5% of the
17 applicable portion of each utility's load for retail
18 customers who are not eligible retail customers, which
19 applicable portion shall equal 75% of the utility's load
20 for retail customers who are not eligible retail customers
21 on February 28, 2017.
22 For the delivery year beginning June 1, 2019, and for
23 each year thereafter, the procurement plans shall include
24 cost-effective renewable energy resources equal to a
25 minimum percentage of each utility's load for all retail
26 customers as follows: 16% by June 1, 2019; increasing by

HB2640- 66 -LRB102 13765 SPS 19115 b
1 1.5% each year thereafter to 25% by June 1, 2025;
2 increasing by at least 2.5% each delivery year thereafter
3 to at least 37.5% by June 1, 2030 and 25% by June 1, 2026
4 and each year thereafter.
5 For each delivery year, the Agency shall first
6 recognize each utility's obligations for that delivery
7 year under existing contracts. Any renewable energy
8 credits under existing contracts, including renewable
9 energy credits as part of renewable energy resources,
10 shall be used to meet the goals set forth in this
11 subsection (c) for the delivery year.
12 (C) Of the renewable energy credits procured under
13 this subsection (c), at least 75% shall come from wind and
14 photovoltaic projects. The long-term renewable resources
15 procurement plan described in subparagraph (A) of this
16 paragraph (1) shall include the procurement of new
17 renewable energy credits in amounts equal to at least
18 10,000,000 renewable energy credits from new wind and
19 solar projects by the end of delivery year 2025, and
20 increasing ratably to reach 45,000,000 new renewable
21 energy credits from wind and solar projects by the end of
22 delivery year 2030 such that the goals in subparagraph (B)
23 of this paragraph (1) are met entirely by procurements of
24 new renewable energy credits from wind and solar projects.
25 Of the following: (i) By the end of the 2020 delivery year:
26 At least 2,000,000 renewable energy credits for each

HB2640- 67 -LRB102 13765 SPS 19115 b
1 delivery year shall come from new wind projects; and At
2 least 2,000,000 renewable energy credits for each delivery
3 year shall come from new photovoltaic projects; of that
4 amount, to the extent possible, the Agency shall procure:
5 50% from wind projects and 50% from solar projects. Of the
6 amount procured from solar projects, the Agency shall
7 procure, to the extent reasonably practicable: at least
8 50% from solar photovoltaic projects using the program
9 outlined in subparagraph (K) of this paragraph (1) from
10 distributed renewable energy generation devices or
11 community renewable generation projects; at least 40% from
12 utility-scale solar projects; at least 2% from brownfield
13 site photovoltaic projects that are not community
14 renewable generation projects; and the remainder shall be
15 determined through the long-term planning process
16 described in subparagraph (A) of this paragraph (1).
17 (ii) By the end of the 2025 delivery year:
18 At least 3,000,000 renewable energy credits
19 for each delivery year shall come from new wind
20 projects; and
21 At least 3,000,000 renewable energy credits
22 for each delivery year shall come from new
23 photovoltaic projects; of that amount, to the
24 extent possible, the Agency shall procure: at
25 least 50% from solar photovoltaic projects using
26 the program outlined in subparagraph (K) of this

HB2640- 68 -LRB102 13765 SPS 19115 b
1 paragraph (1) from distributed renewable energy
2 devices or community renewable generation
3 projects; at least 40% from utility-scale solar
4 projects; at least 2% from brownfield site
5 photovoltaic projects that are not community
6 renewable generation projects; and the remainder
7 shall be determined through the long-term planning
8 process described in subparagraph (A) of this
9 paragraph (1).
10 (iii) By the end of the 2030 delivery year:
11 At least 4,000,000 renewable energy credits
12 for each delivery year shall come from new wind
13 projects; and
14 At least 4,000,000 renewable energy credits
15 for each delivery year shall come from new
16 photovoltaic projects; of that amount, to the
17 extent possible, the Agency shall procure: at
18 least 50% from solar photovoltaic projects using
19 the program outlined in subparagraph (K) of this
20 paragraph (1) from distributed renewable energy
21 devices or community renewable generation
22 projects; at least 40% from utility-scale solar
23 projects; at least 2% from brownfield site
24 photovoltaic projects that are not community
25 renewable generation projects; and the remainder
26 shall be determined through the long-term planning

HB2640- 69 -LRB102 13765 SPS 19115 b
1 process described in subparagraph (A) of this
2 paragraph (1).
3 For purposes of this Section:
4 "New wind projects" means wind renewable
5 energy facilities that are energized after June 1,
6 2017 for the delivery year commencing June 1, 2017
7 or within 3 years after the date the Commission
8 approves contracts for subsequent delivery years.
9 "New photovoltaic projects" means photovoltaic
10 renewable energy facilities that are energized
11 after June 1, 2017. Photovoltaic projects
12 developed under Section 1-56 of this Act shall not
13 apply towards the new photovoltaic project
14 requirements in this subparagraph (C). For
15 purposes of calculating whether the Agency has
16 procured enough new wind and solar renewable
17 energy credits required by this subparagraph (C),
18 renewable energy facilities that have a multi-year
19 renewable energy credit delivery contract with the
20 utility through at least delivery year 2030 shall
21 be considered new, however no renewable energy
22 credits from contracts entered into before June 1,
23 2021 shall be used to calculate whether the Agency
24 has procured the correct proportion of new wind
25 and new solar contracts described in this
26 subparagraph (C) for delivery year 2025 and

HB2640- 70 -LRB102 13765 SPS 19115 b
1 thereafter.
2 (D) Renewable energy credits shall be cost effective.
3 For purposes of this subsection (c), "cost effective"
4 means that the costs of procuring renewable energy
5 resources do not cause the limit stated in subparagraph
6 (E) of this paragraph (1) to be exceeded and, for
7 renewable energy credits procured through a competitive
8 procurement event, do not exceed benchmarks based on
9 market prices for like products in the region. For
10 purposes of this subsection (c), "like products" means
11 contracts for renewable energy credits from the same or
12 substantially similar technology, same or substantially
13 similar vintage (new or existing), the same or
14 substantially similar quantity, and the same or
15 substantially similar contract length and structure.
16 Benchmarks shall be developed by the procurement
17 administrator, in consultation with the Commission staff,
18 Agency staff, and the procurement monitor and shall be
19 subject to Commission review and approval. If price
20 benchmarks for like products in the region are not
21 available, the procurement administrator shall establish
22 price benchmarks based on publicly available data on
23 regional technology costs and expected current and future
24 regional energy prices. The benchmarks in this Section
25 shall not be used to curtail or otherwise reduce
26 contractual obligations entered into by or through the

HB2640- 71 -LRB102 13765 SPS 19115 b
1 Agency prior to June 1, 2017 (the effective date of Public
2 Act 99-906).
3 (E) For purposes of this subsection (c), the required
4 procurement of cost-effective renewable energy resources
5 for a particular year commencing prior to June 1, 2017
6 shall be measured as a percentage of the actual amount of
7 electricity (megawatt-hours) supplied by the electric
8 utility to eligible retail customers in the delivery year
9 ending immediately prior to the procurement, and, for
10 delivery years commencing on and after June 1, 2017, the
11 required procurement of cost-effective renewable energy
12 resources for a particular year shall be measured as a
13 percentage of the actual amount of electricity
14 (megawatt-hours) delivered by the electric utility in the
15 delivery year ending immediately prior to the procurement,
16 to all retail customers in its service territory. For
17 purposes of this subsection (c), the amount paid per
18 kilowatthour means the total amount paid for electric
19 service expressed on a per kilowatthour basis. For
20 purposes of this subsection (c), the total amount paid for
21 electric service includes without limitation amounts paid
22 for supply, capacity, transmission, distribution,
23 surcharges, and add-on taxes.
24 Notwithstanding the requirements of this subsection
25 (c), the total of renewable energy resources procured
26 under the procurement plan for any single year shall be

HB2640- 72 -LRB102 13765 SPS 19115 b
1 subject to the limitations of this subparagraph (E). Such
2 procurement shall be reduced for all retail customers
3 based on the amount necessary to limit the annual
4 estimated average net increase due to the costs of these
5 resources included in the amounts paid by eligible retail
6 customers in connection with electric service to no more
7 than the greater of the percentage limitations as included
8 in paragraphs (1), (2), and (3) of subsection (m) of
9 Section 8-103B of the Public Utilities Act 2.015% of the
10 amount paid per kilowatthour by those customers during the
11 year ending May 31, 2009 2007 or the incremental amount
12 per kilowatthour paid for these resources in 2011. To
13 arrive at a maximum dollar amount of renewable energy
14 resources to be procured for the particular delivery year,
15 the resulting per kilowatthour amount shall be applied to
16 the actual amount of kilowatthours of electricity
17 delivered, or applicable portion of such amount as
18 specified in paragraph (1) of this subsection (c), as
19 applicable, by the electric utility in the delivery year
20 immediately prior to the procurement to all retail
21 customers in its service territory. The calculations
22 required by this subparagraph (E) shall be made only once
23 for each delivery year at the time that the renewable
24 energy resources are procured. Once the determination as
25 to the amount of renewable energy resources to procure is
26 made based on the calculations set forth in this

HB2640- 73 -LRB102 13765 SPS 19115 b
1 subparagraph (E) and the contracts procuring those amounts
2 are executed, no subsequent rate impact determinations
3 shall be made and no adjustments to those contract amounts
4 shall be allowed. All costs incurred under such contracts
5 shall be fully recoverable by the electric utility as
6 provided in this Section.
7 (E-5) If the limitation on the amount of renewable
8 energy resources procured in subparagraph (E) of this
9 paragraph (1) would prevent the Agency from meeting all of
10 the goals in this subsection (c), the Agency shall procure
11 additional renewable energy resources up to an amount
12 equal to the Social Cost of Carbon as defined in
13 subsection (d-5) of this Section as of January 1, 2021
14 multiplied by the amount of new renewable energy credits
15 to be procured pursuant to the new renewable energy credit
16 procurement requirements of subparagraph (C) of this
17 paragraph (1) from the new build requirements for the
18 relevant planning year. The deemed savings of renewable
19 energy shall not be subject to the limitations in
20 subparagraph (E) of this paragraph (1). The utilities
21 shall be entitled to recover the total cost associated
22 with procuring renewable energy credits required by this
23 Section regardless of whether the costs are subject to the
24 limitations described in subparagraph (E) of this
25 paragraph (1) through the automatic adjustment clause
26 tariff under subsection (k) of Section 16-108 of the

HB2640- 74 -LRB102 13765 SPS 19115 b
1 Public Utilities Act.
2 (F) If the limitation on the amount of renewable
3 energy resources procured in subparagraph (E) of this
4 paragraph (1) prevents the Agency from meeting all of the
5 goals in this subsection (c), the Agency's long-term plan
6 shall prioritize compliance with the requirements of this
7 subsection (c) regarding renewable energy credits in the
8 following order:
9 (i) renewable energy credits under existing
10 contractual obligations;
11 (i-5) funding for the Illinois Solar for All
12 Program, as described in subparagraph (O) of this
13 paragraph (1);
14 (ii) renewable energy credits necessary to comply
15 with the new wind and new photovoltaic procurement
16 requirements described in items (i) through (iii) of
17 subparagraph (C) of this paragraph (1); and
18 (iii) renewable energy credits necessary to meet
19 the remaining requirements of this subsection (c).
20 (G) The following provisions shall apply to the
21 Agency's procurement of renewable energy credits under
22 this subsection (c):
23 (i) Notwithstanding whether a long-term renewable
24 resources procurement plan has been approved, the
25 Agency shall conduct an initial forward procurement
26 for renewable energy credits from new utility-scale

HB2640- 75 -LRB102 13765 SPS 19115 b
1 wind projects within 160 days after June 1, 2017 (the
2 effective date of Public Act 99-906). For the purposes
3 of this initial forward procurement, the Agency shall
4 solicit 15-year contracts for delivery of 1,000,000
5 renewable energy credits delivered annually from new
6 utility-scale wind projects to begin delivery on June
7 1, 2019, if available, but not later than June 1, 2021,
8 unless the project has delays in the establishment of
9 an operating interconnection with the applicable
10 transmission or distribution system as a result of the
11 actions or inactions of the transmission or
12 distribution provider, or other causes for force
13 majeure as outlined in the procurement contract, in
14 which case, not later than June 1, 2022. Payments to
15 suppliers of renewable energy credits shall commence
16 upon delivery. Renewable energy credits procured under
17 this initial procurement shall be included in the
18 Agency's long-term plan and shall apply to all
19 renewable energy goals in this subsection (c).
20 (ii) Notwithstanding whether a long-term renewable
21 resources procurement plan has been approved, the
22 Agency shall conduct an initial forward procurement
23 for renewable energy credits from new utility-scale
24 solar projects and brownfield site photovoltaic
25 projects within one year after June 1, 2017 (the
26 effective date of Public Act 99-906). For the purposes

HB2640- 76 -LRB102 13765 SPS 19115 b
1 of this initial forward procurement, the Agency shall
2 solicit 15-year contracts for delivery of 1,000,000
3 renewable energy credits delivered annually from new
4 utility-scale solar projects and brownfield site
5 photovoltaic projects to begin delivery on June 1,
6 2019, if available, but not later than June 1, 2021,
7 unless the project has delays in the establishment of
8 an operating interconnection with the applicable
9 transmission or distribution system as a result of the
10 actions or inactions of the transmission or
11 distribution provider, or other causes for force
12 majeure as outlined in the procurement contract, in
13 which case, not later than June 1, 2022. The Agency may
14 structure this initial procurement in one or more
15 discrete procurement events. Payments to suppliers of
16 renewable energy credits shall commence upon delivery.
17 Renewable energy credits procured under this initial
18 procurement shall be included in the Agency's
19 long-term plan and shall apply to all renewable energy
20 goals in this subsection (c).
21 (iii) Notwithstanding whether the Commission has
22 approved the periodic long-term renewable resources
23 procurement plan revision described in Section
24 16-111.5 of the Public Utilities Act, the Agency shall
25 conduct at least one subsequent forward procurement
26 for renewable energy credits from new utility-scale

HB2640- 77 -LRB102 13765 SPS 19115 b
1 wind projects and new utility-scale solar projects
2 within 120 days after the effective date of this
3 amendatory Act of the 102nd General Assembly in
4 quantities needed to meet the requirements of
5 subparagraph (C) Subsequent forward procurements for
6 utility-scale wind projects shall solicit at least
7 1,000,000 renewable energy credits delivered annually
8 per procurement event and shall be planned, scheduled,
9 and designed such that the cumulative amount of
10 renewable energy credits delivered from all new wind
11 projects in each delivery year shall not exceed the
12 Agency's projection of the cumulative amount of
13 renewable energy credits that will be delivered from
14 all new photovoltaic projects, including utility-scale
15 and distributed photovoltaic devices, in the same
16 delivery year at the time scheduled for wind contract
17 delivery.
18 (iv) For all competitive procurements under this
19 subparagraph (G) and any procurements required under
20 subparagraph (C) of new utility-scale wind and new
21 utility-scale solar, the Agency shall allow
22 respondents to bid a fixed price per renewable energy
23 credit or a variable price per renewable energy credit
24 that is indexed to the ComEd Hub for projects
25 interconnecting to PJM Interconnection LLC or the
26 Illinois Hub for projects interconnecting to MISO.

HB2640- 78 -LRB102 13765 SPS 19115 b
1 Variable price renewable energy credit bids shall be
2 limited to the first 3 new utility-scale wind and
3 solar procurements following the effective date of
4 this amendatory act of the 102nd General Assembly.
5 Variable renewable energy credit bids shall be based
6 on the difference between the offer strike price and
7 the index price that shall be developed by the
8 Illinois Power Agency and approved by the Illinois
9 Commerce Commission. Variable price renewable energy
10 credits shall not exceed more than 40% or less than 20%
11 of the total supply for new utility-scale wind and
12 solar procurements in a procurement year. The Illinois
13 Commerce Commission, in consultation with the Illinois
14 Power Agency, shall determine that variable price
15 renewable energy credit bids are prudent within the
16 renewables resources budget If, at any time after the
17 time set for delivery of renewable energy credits
18 pursuant to the initial procurements in items (i) and
19 (ii) of this subparagraph (G), the cumulative amount
20 of renewable energy credits projected to be delivered
21 from all new wind projects in a given delivery year
22 exceeds the cumulative amount of renewable energy
23 credits projected to be delivered from all new
24 photovoltaic projects in that delivery year by 200,000
25 or more renewable energy credits, then the Agency
26 shall within 60 days adjust the procurement programs

HB2640- 79 -LRB102 13765 SPS 19115 b
1 in the long-term renewable resources procurement plan
2 to ensure that the projected cumulative amount of
3 renewable energy credits to be delivered from all new
4 wind projects does not exceed the projected cumulative
5 amount of renewable energy credits to be delivered
6 from all new photovoltaic projects by 200,000 or more
7 renewable energy credits, provided that nothing in
8 this Section shall preclude the projected cumulative
9 amount of renewable energy credits to be delivered
10 from all new photovoltaic projects from exceeding the
11 projected cumulative amount of renewable energy
12 credits to be delivered from all new wind projects in
13 each delivery year and provided further that nothing
14 in this item (iv) shall require the curtailment of an
15 executed contract. The Agency shall update, on a
16 quarterly basis, its projection of the renewable
17 energy credits to be delivered from all projects in
18 each delivery year. Notwithstanding anything to the
19 contrary, the Agency may adjust the timing of
20 procurement events conducted under this subparagraph
21 (G). The long-term renewable resources procurement
22 plan shall set forth the process by which the
23 adjustments may be made.
24 (v) All procurements under this subparagraph (G)
25 shall comply with the geographic requirements in
26 subparagraph (I) of this paragraph (1) and shall

HB2640- 80 -LRB102 13765 SPS 19115 b
1 follow the procurement processes and procedures
2 described in this Section and Section 16-111.5 of the
3 Public Utilities Act to the extent practicable, and
4 these processes and procedures may be expedited to
5 accommodate the schedule established by this
6 subparagraph (G).
7 (H) The procurement of renewable energy resources for
8 a given delivery year shall be reduced as described in
9 this subparagraph (H) if an alternative retail electric
10 supplier meets the requirements described in this
11 subparagraph (H).
12 (i) Within 45 days after June 1, 2017 (the
13 effective date of Public Act 99-906), an alternative
14 retail electric supplier or its successor shall submit
15 an informational filing to the Illinois Commerce
16 Commission certifying that, as of December 31, 2015,
17 the alternative retail electric supplier owned one or
18 more electric generating facilities that generates
19 renewable energy resources as defined in Section 1-10
20 of this Act, provided that such facilities are not
21 powered by wind or photovoltaics, and the facilities
22 generate one renewable energy credit for each
23 megawatthour of energy produced from the facility.
24 The informational filing shall identify each
25 facility that was eligible to satisfy the alternative
26 retail electric supplier's obligations under Section

HB2640- 81 -LRB102 13765 SPS 19115 b
1 16-115D of the Public Utilities Act as described in
2 this item (i).
3 (ii) For a given delivery year, the alternative
4 retail electric supplier may elect to supply its
5 retail customers with renewable energy credits from
6 the facility or facilities described in item (i) of
7 this subparagraph (H) that continue to be owned by the
8 alternative retail electric supplier.
9 (iii) The alternative retail electric supplier
10 shall notify the Agency and the applicable utility, no
11 later than February 28 of the year preceding the
12 applicable delivery year or 15 days after June 1, 2017
13 (the effective date of Public Act 99-906), whichever
14 is later, of its election under item (ii) of this
15 subparagraph (H) to supply renewable energy credits to
16 retail customers of the utility. Such election shall
17 identify the amount of renewable energy credits to be
18 supplied by the alternative retail electric supplier
19 to the utility's retail customers and the source of
20 the renewable energy credits identified in the
21 informational filing as described in item (i) of this
22 subparagraph (H), subject to the following
23 limitations:
24 For the delivery year beginning June 1, 2018,
25 the maximum amount of renewable energy credits to
26 be supplied by an alternative retail electric

HB2640- 82 -LRB102 13765 SPS 19115 b
1 supplier under this subparagraph (H) shall be 68%
2 multiplied by 25% multiplied by 14.5% multiplied
3 by the amount of metered electricity
4 (megawatt-hours) delivered by the alternative
5 retail electric supplier to Illinois retail
6 customers during the delivery year ending May 31,
7 2016.
8 For delivery years beginning June 1, 2019 and
9 each year thereafter, the maximum amount of
10 renewable energy credits to be supplied by an
11 alternative retail electric supplier under this
12 subparagraph (H) shall be 68% multiplied by 50%
13 multiplied by 16% multiplied by the amount of
14 metered electricity (megawatt-hours) delivered by
15 the alternative retail electric supplier to
16 Illinois retail customers during the delivery year
17 ending May 31, 2016, provided that the 16% value
18 shall increase by 1.5% each delivery year
19 thereafter to 25% by the delivery year beginning
20 June 1, 2025, and thereafter the 25% value shall
21 apply to each delivery year.
22 For each delivery year, the total amount of
23 renewable energy credits supplied by all alternative
24 retail electric suppliers under this subparagraph (H)
25 shall not exceed 9% of the Illinois target renewable
26 energy credit quantity. The Illinois target renewable

HB2640- 83 -LRB102 13765 SPS 19115 b
1 energy credit quantity for the delivery year beginning
2 June 1, 2018 is 14.5% multiplied by the total amount of
3 metered electricity (megawatt-hours) delivered in the
4 delivery year immediately preceding that delivery
5 year, provided that the 14.5% shall increase by 1.5%
6 each delivery year thereafter to 25% by the delivery
7 year beginning June 1, 2025, and thereafter the 25%
8 value shall apply to each delivery year.
9 If the requirements set forth in items (i) through
10 (iii) of this subparagraph (H) are met, the charges
11 that would otherwise be applicable to the retail
12 customers of the alternative retail electric supplier
13 under paragraph (6) of this subsection (c) for the
14 applicable delivery year shall be reduced by the ratio
15 of the quantity of renewable energy credits supplied
16 by the alternative retail electric supplier compared
17 to that supplier's target renewable energy credit
18 quantity. The supplier's target renewable energy
19 credit quantity for the delivery year beginning June
20 1, 2018 is 14.5% multiplied by the total amount of
21 metered electricity (megawatt-hours) delivered by the
22 alternative retail supplier in that delivery year,
23 provided that the 14.5% shall increase by 1.5% each
24 delivery year thereafter to 25% by the delivery year
25 beginning June 1, 2025, and thereafter the 25% value
26 shall apply to each delivery year.

HB2640- 84 -LRB102 13765 SPS 19115 b
1 On or before April 1 of each year, the Agency shall
2 annually publish a report on its website that
3 identifies the aggregate amount of renewable energy
4 credits supplied by alternative retail electric
5 suppliers under this subparagraph (H).
6 (I) The Agency shall design its long-term renewable
7 energy procurement plan to maximize the State's interest
8 in the health, safety, and welfare of its residents,
9 including but not limited to minimizing sulfur dioxide,
10 nitrogen oxide, particulate matter and other pollution
11 that adversely affects public health in this State,
12 increasing fuel and resource diversity in this State,
13 enhancing the reliability and resiliency of the
14 electricity distribution system in this State, meeting
15 goals to limit carbon dioxide emissions under federal or
16 State law, and contributing to a cleaner and healthier
17 environment for the citizens of this State. In order to
18 further these legislative purposes, renewable energy
19 credits shall be eligible to be counted toward the
20 renewable energy requirements of this subsection (c) if
21 they are generated from facilities located in this State.
22 The Agency may qualify renewable energy credits from
23 facilities located in states adjacent to Illinois if the
24 generator demonstrates and the Agency determines that the
25 operation of such facility or facilities will help promote
26 the State's interest in the health, safety, and welfare of

HB2640- 85 -LRB102 13765 SPS 19115 b
1 its residents based on the public interest criteria
2 described above. To ensure that the public interest
3 criteria are applied to the procurement and given full
4 effect, the Agency's long-term procurement plan shall
5 describe in detail how each public interest factor shall
6 be considered and weighted for facilities located in
7 states adjacent to Illinois.
8 (J) In order to promote the competitive development of
9 renewable energy resources in furtherance of the State's
10 interest in the health, safety, and welfare of its
11 residents, renewable energy credits shall not be eligible
12 to be counted toward the renewable energy requirements of
13 this subsection (c) if they are sourced from a generating
14 unit whose costs were being recovered through rates
15 regulated by this State or any other state or states on or
16 after January 1, 2017. Each contract executed to purchase
17 renewable energy credits under this subsection (c) shall
18 provide for the contract's termination if the costs of the
19 generating unit supplying the renewable energy credits
20 subsequently begin to be recovered through rates regulated
21 by this State or any other state or states; and each
22 contract shall further provide that, in that event, the
23 supplier of the credits must return 110% of all payments
24 received under the contract. Amounts returned under the
25 requirements of this subparagraph (J) shall be retained by
26 the utility and all of these amounts shall be used for the

HB2640- 86 -LRB102 13765 SPS 19115 b
1 procurement of additional renewable energy credits from
2 new wind or new photovoltaic resources as defined in this
3 subsection (c). The long-term plan shall provide that
4 these renewable energy credits shall be procured in the
5 next procurement event.
6 Notwithstanding the limitations of this subparagraph
7 (J), renewable energy credits sourced from generating
8 units that are constructed, purchased, owned, or leased by
9 an electric utility as part of an approved project,
10 program, or pilot under Section 1-56 of this Act shall be
11 eligible to be counted toward the renewable energy
12 requirements of this subsection (c), regardless of how the
13 costs of these units are recovered.
14 (K) The long-term renewable resources procurement plan
15 developed by the Agency in accordance with subparagraph
16 (A) of this paragraph (1) shall include an Adjustable
17 Block program for the procurement of renewable energy
18 credits from new photovoltaic projects that are
19 distributed renewable energy generation devices or new
20 photovoltaic community renewable generation projects. The
21 Adjustable Block program shall be designed to be
22 continuously open in order to provide for the steady,
23 predictable, and sustainable growth of new solar
24 photovoltaic development in Illinois. To this end, the
25 Adjustable Block program shall provide a transparent
26 annual schedule of prices and quantities to enable the

HB2640- 87 -LRB102 13765 SPS 19115 b
1 photovoltaic market to scale up and for renewable energy
2 credit prices to adjust at a predictable rate over time.
3 The prices set by the Adjustable Block program can be
4 reflected as a set value or as the product of a formula.
5 The Adjustable Block program shall include for each
6 category of eligible projects: a schedule of standard
7 block purchase prices to be offered; a series of steps,
8 with associated nameplate capacity and purchase prices
9 that adjust from step to step; and automatic opening of
10 the next step as soon as the nameplate capacity and
11 available purchase prices for an open step are fully
12 committed or reserved. Only projects energized on or after
13 June 1, 2017 shall be eligible for the Adjustable Block
14 program. The Agency shall develop program features and
15 implementation processes that create consistent market
16 signals, making the program predictable and sustainable
17 for solar industry companies, thus allowing them to scale
18 up long-term Illinois-based hiring and investment
19 activities. For each block group the Agency shall
20 determine the number of blocks, the amount of generation
21 capacity in each block, and the purchase price for each
22 block, provided that the purchase price provided and the
23 total amount of generation in all blocks for all block
24 groups shall be sufficient to meet the goals in this
25 subsection (c). The Agency shall establish program
26 eligibility requirements that ensure that projects that

HB2640- 88 -LRB102 13765 SPS 19115 b
1 enter the program are sufficiently mature to indicate a
2 demonstrable path to completion. The Agency may
3 periodically review its prior decisions establishing the
4 number of blocks, the amount of generation capacity in
5 each block, and the purchase price for each block, and may
6 propose, on an expedited basis, changes to these
7 previously set values, including but not limited to
8 redistributing these amounts and the available funds as
9 necessary and appropriate, subject to Commission approval
10 as part of the periodic plan revision process described in
11 Section 16-111.5 of the Public Utilities Act. The Agency
12 may define different block sizes, purchase prices, or
13 other distinct terms and conditions for projects located
14 in different utility service territories if the Agency
15 deems it necessary to meet the goals in this subsection
16 (c).
17 The Adjustable Block program shall include at least
18 the following block groups in at least the following
19 amounts, which may be adjusted upon review by the Agency
20 and approval by the Commission as described in this
21 subparagraph (K):
22 (i) At least 25% from distributed renewable energy
23 generation devices with a nameplate capacity of no
24 more than 25 10 kilowatts.
25 (ii) At least 25% from distributed renewable
26 energy generation devices with a nameplate capacity of

HB2640- 89 -LRB102 13765 SPS 19115 b
1 more than 25 10 kilowatts and no more than 2,000
2 kilowatts. The Agency may create sub-categories within
3 this category to account for the differences between
4 projects for small commercial customers, large
5 commercial customers, and public or non-profit
6 customers.
7 (iii) At least 25% from photovoltaic community
8 renewable generation projects.
9 (iv) The remaining 25% shall be allocated as
10 specified by the Agency in the long-term renewable
11 resources procurement plan in order to respond to
12 market demand.
13 The Adjustable Block program shall be designed to
14 ensure that renewable energy credits are procured from
15 photovoltaic distributed renewable energy generation
16 devices and new photovoltaic community renewable energy
17 generation projects in diverse locations and are not
18 concentrated in a few geographic areas.
19 (L) The procurement of photovoltaic renewable energy
20 credits under items (i) through (iv) of subparagraph (K)
21 of this paragraph (1) shall be subject to the following
22 contract and payment terms:
23 (i) The Agency shall procure contracts of at least
24 15 years in length.
25 (ii) For those renewable energy credits that
26 qualify and are procured under item (i) of

HB2640- 90 -LRB102 13765 SPS 19115 b
1 subparagraph (K) of this paragraph (1), the renewable
2 energy credit purchase price shall be paid in full by
3 the contracting utilities at the time that the
4 facility producing the renewable energy credits is
5 interconnected at the distribution system level of the
6 utility and energized. The electric utility shall
7 receive and retire all renewable energy credits
8 generated by the project for the first 15 years of
9 operation.
10 (iii) For those renewable energy credits that
11 qualify and are procured under item (ii) and (iii) of
12 subparagraph (K) of this paragraph (1) and any
13 additional categories of distributed generation
14 included in the long-term renewable resources
15 procurement plan and approved by the Commission, 20
16 percent of the renewable energy credit purchase price
17 shall be paid by the contracting utilities at the time
18 that the facility producing the renewable energy
19 credits is interconnected at the distribution system
20 level of the utility and energized. The remaining
21 portion shall be paid ratably over the subsequent
22 4-year period. The electric utility shall receive and
23 retire all renewable energy credits generated by the
24 project for the first 15 years of operation.
25 (iv) Each contract shall include provisions to
26 ensure the delivery of the renewable energy credits

HB2640- 91 -LRB102 13765 SPS 19115 b
1 for the full term of the contract.
2 (v) The utility shall be the counterparty to the
3 contracts executed under this subparagraph (L) that
4 are approved by the Commission under the process
5 described in Section 16-111.5 of the Public Utilities
6 Act. No contract shall be executed for an amount that
7 is less than one renewable energy credit per year.
8 (vi) If, at any time, approved applications for
9 the Adjustable Block program exceed funds collected by
10 the electric utility or would cause the Agency to
11 exceed the limitation described in subparagraph (E) of
12 this paragraph (1) on the amount of renewable energy
13 resources that may be procured, then the Agency shall
14 consider future uncommitted funds to be reserved for
15 these contracts on a first-come, first-served basis,
16 with the delivery of renewable energy credits required
17 beginning at the time that the reserved funds become
18 available.
19 (vii) Nothing in this Section shall require the
20 utility to advance any payment or pay any amounts that
21 exceed the actual amount of revenues collected by the
22 utility under paragraph (6) of this subsection (c) and
23 subsection (k) of Section 16-108 of the Public
24 Utilities Act, and contracts executed under this
25 Section shall expressly incorporate this limitation.
26 (viii) Notwithstanding items (ii) and (iii) of

HB2640- 92 -LRB102 13765 SPS 19115 b
1 this subparagraph (L), the Agency shall not be
2 restricted from offering additional payment structures
3 if it determines that such adjustments will better
4 achieve the goals of this subsection (c). Any such
5 adjustments shall be approved by the Commission as a
6 long-term plan amendment under Section 16-111.5 of the
7 Public Utilities Act.
8 (M) The Agency shall be authorized to retain one or
9 more experts or expert consulting firms to develop,
10 administer, implement, operate, and evaluate the
11 Adjustable Block program described in subparagraph (K) of
12 this paragraph (1), and the Agency shall retain the
13 consultant or consultants in the same manner, to the
14 extent practicable, as the Agency retains others to
15 administer provisions of this Act, including, but not
16 limited to, the procurement administrator. The selection
17 of experts and expert consulting firms and the procurement
18 process described in this subparagraph (M) are exempt from
19 the requirements of Section 20-10 of the Illinois
20 Procurement Code, under Section 20-10 of that Code. The
21 Agency shall strive to minimize administrative expenses in
22 the implementation of the Adjustable Block program. Funds
23 needed to cover the administrative expenses for the
24 implementation of the Adjustable Block program shall not
25 be included as part of the limitations described in
26 subparagraph (E). The utilities shall be entitled to

HB2640- 93 -LRB102 13765 SPS 19115 b
1 recover the costs detailed in this subparagraph (M)
2 regardless of whether the costs are subject to the
3 limitations described in subparagraph (E) through the
4 automatic adjustment clause tariff under subsection (k) of
5 Section 16-108 of the Public Utilities Act.
6 The Agency and its consultant or consultants shall
7 monitor block activity, share program activity with
8 stakeholders and conduct regularly scheduled meetings to
9 discuss program activity and market conditions. If
10 necessary, the Agency may make prospective administrative
11 adjustments to the Adjustable Block program design, such
12 as redistributing available funds or making adjustments to
13 purchase prices as necessary to achieve the goals of this
14 subsection (c). Program modifications to any price,
15 capacity block, or other program element that do not
16 deviate from the Commission's approved value by more than
17 25% shall take effect immediately and are not subject to
18 Commission review and approval. Program modifications to
19 any price, capacity block, or other program element that
20 deviate more than 25% from the Commission's approved value
21 must be approved by the Commission as a long-term plan
22 amendment under Section 16-111.5 of the Public Utilities
23 Act. The Agency shall consider stakeholder feedback when
24 making adjustments to the Adjustable Block design and
25 shall notify stakeholders in advance of any planned
26 changes.

HB2640- 94 -LRB102 13765 SPS 19115 b
1 (N) The long-term renewable resources procurement plan
2 required by this subsection (c) shall include a community
3 renewable generation program. The Agency shall establish
4 the terms, conditions, and program requirements for
5 community renewable generation projects with a goal to
6 expand renewable energy generating facility access to a
7 broader group of energy consumers, to ensure robust
8 participation opportunities for residential and small
9 commercial customers and those who cannot install
10 renewable energy on their own properties. Any plan
11 approved by the Commission shall allow subscriptions to
12 community renewable generation projects to be portable and
13 transferable. For purposes of this subparagraph (N),
14 "portable" means that subscriptions may be retained by the
15 subscriber even if the subscriber relocates or changes its
16 address within the same utility service territory; and
17 "transferable" means that a subscriber may assign or sell
18 subscriptions to another person within the same utility
19 service territory.
20 Electric utilities shall provide a monetary credit to
21 a subscriber's subsequent bill for service for the
22 proportional output of a community renewable generation
23 project attributable to that subscriber as specified in
24 Section 16-107.5 of the Public Utilities Act.
25 The Agency shall purchase renewable energy credits
26 from subscribed shares of photovoltaic community renewable

HB2640- 95 -LRB102 13765 SPS 19115 b
1 generation projects through the Adjustable Block program
2 described in subparagraph (K) of this paragraph (1) or
3 through the Illinois Solar for All Program described in
4 Section 1-56 of this Act. The project shall be deemed to be
5 fully subscribed and the Agency shall purchase all of the
6 renewable energy credits from photovoltaic community
7 renewable generation projects as long as a minimum of 80%
8 of the shares are subscribed. The electric utility shall
9 purchase any unsubscribed energy from community renewable
10 generation projects that are Qualifying Facilities ("QF")
11 under the electric utility's tariff for purchasing the
12 output from QFs under Public Utilities Regulatory Policies
13 Act of 1978.
14 The owners of and any subscribers to a community
15 renewable generation project shall not be considered
16 public utilities or alternative retail electricity
17 suppliers under the Public Utilities Act solely as a
18 result of their interest in or subscription to a community
19 renewable generation project and shall not be required to
20 become an alternative retail electric supplier by
21 participating in a community renewable generation project
22 with a public utility.
23 (O) For the delivery year beginning June 1, 2018, the
24 long-term renewable resources procurement plan required by
25 this subsection (c) shall provide for the Agency to
26 procure contracts to continue offering the Illinois Solar

HB2640- 96 -LRB102 13765 SPS 19115 b
1 for All Program described in subsection (b) of Section
2 1-56 of this Act, and the contracts approved by the
3 Commission shall be executed by the utilities that are
4 subject to this subsection (c). The long-term renewable
5 resources procurement plan shall allocate $50,000,000 5%
6 of the funds available under the plan for the applicable
7 delivery year, or $10,000,000 per delivery year, whichever
8 is greater, to fund the programs, and the plan shall
9 determine the amount of funding to be apportioned to the
10 programs identified in subsection (b) of Section 1-56 of
11 this Act; provided that for the delivery years beginning
12 June 1, 2017, June 1, 2021, and June 1, 2025, the long-term
13 renewable resources procurement plan shall allocate an
14 additional 10% of the funds available under the plan for
15 the applicable delivery year, or $20,000,000 per delivery
16 year, whichever is greater, and $10,000,000 that of such
17 funds in such year shall be used by an electric utility
18 that serves more than 3,000,000 retail customers in the
19 State to implement a Commission-approved plan under
20 Section 16-108.12 of the Public Utilities Act. Funds
21 allocated under this subparagraph (O) shall not be
22 included as part of the limitations described in
23 subparagraph (E) of this Section. The utilities shall be
24 entitled to recover the total cost associated with
25 procuring renewable energy credits detailed in this
26 subparagraph (O) regardless of whether the costs are

HB2640- 97 -LRB102 13765 SPS 19115 b
1 subject to the limitations described in subparagraph (E)
2 through the automatic adjustment clause tariff under
3 subsection (k) of Section 16-108 of the Public Utilities
4 Act. In making the determinations required under this
5 subparagraph (O), the Commission shall consider the
6 experience and performance under the programs and any
7 evaluation reports. The Commission shall also provide for
8 an independent evaluation of those programs on a periodic
9 basis that are funded under this subparagraph (O).
10 (P) All programs and procurements under this
11 subsection (c) shall be designed to encourage
12 participating projects to use a diverse and equitable
13 workforce and a diverse set of contractors, including
14 minority-owned businesses, disadvantaged businesses,
15 trade unions, graduates of any workforce training programs
16 administered under this Act, and small businesses. Any
17 incremental costs in renewable energy credits associated
18 with incentives or requirements to meet goals associated
19 with geographic diversity, workforce diversity,
20 subcontractor diversity, or any other public policies
21 determined by the Agency and approved by the Commission,
22 shall not be included as part of the limitations described
23 in subparagraph (E). The utilities shall be entitled to
24 recover the incremental costs associated with procuring
25 renewable energy credits that also meet the public policy
26 goals detailed in this subparagraph (P) regardless of

HB2640- 98 -LRB102 13765 SPS 19115 b
1 whether the costs are subject to the limitations described
2 in subparagraph (E) through the automatic adjustment
3 clause tariff under subsection (k) of Section 16-108 of
4 the Public Utilities Act.
5 (2) (Blank).
6 (3) (Blank).
7 (4) The electric utility shall retire all renewable
8 energy credits used to comply with the standard.
9 (5) Beginning with the 2010 delivery year and ending
10 June 1, 2017, an electric utility subject to this
11 subsection (c) shall apply the lesser of the maximum
12 alternative compliance payment rate or the most recent
13 estimated alternative compliance payment rate for its
14 service territory for the corresponding compliance period,
15 established pursuant to subsection (d) of Section 16-115D
16 of the Public Utilities Act to its retail customers that
17 take service pursuant to the electric utility's hourly
18 pricing tariff or tariffs. The electric utility shall
19 retain all amounts collected as a result of the
20 application of the alternative compliance payment rate or
21 rates to such customers, and, beginning in 2011, the
22 utility shall include in the information provided under
23 item (1) of subsection (d) of Section 16-111.5 of the
24 Public Utilities Act the amounts collected under the
25 alternative compliance payment rate or rates for the prior
26 year ending May 31. Notwithstanding any limitation on the

HB2640- 99 -LRB102 13765 SPS 19115 b
1 procurement of renewable energy resources imposed by item
2 (2) of this subsection (c), the Agency shall increase its
3 spending on the purchase of renewable energy resources to
4 be procured by the electric utility for the next plan year
5 by an amount equal to the amounts collected by the utility
6 under the alternative compliance payment rate or rates in
7 the prior year ending May 31.
8 (6) The electric utility shall be entitled to recover
9 all of its costs associated with the procurement of
10 renewable energy credits under plans approved under this
11 Section and Section 16-111.5 of the Public Utilities Act.
12 These costs shall include associated reasonable expenses
13 for implementing the procurement programs, including, but
14 not limited to, the costs of administering and evaluating
15 the Adjustable Block program, through an automatic
16 adjustment clause tariff in accordance with subsection (k)
17 of Section 16-108 of the Public Utilities Act. The costs
18 associated with implementing procurement programs,
19 including, but not limited to, the costs of administering
20 and evaluating the Adjustable Block program, shall not be
21 included as part of the limitations described in
22 subparagraph (E) of paragraph (1).
23 (7) Renewable energy credits procured from new
24 photovoltaic projects or new distributed renewable energy
25 generation devices under this Section after June 1, 2017
26 (the effective date of Public Act 99-906) must be procured

HB2640- 100 -LRB102 13765 SPS 19115 b
1 from devices installed by a qualified person in compliance
2 with the requirements of Section 16-128A of the Public
3 Utilities Act and any rules or regulations adopted
4 thereunder.
5 In meeting the renewable energy requirements of this
6 subsection (c), to the extent feasible and consistent with
7 State and federal law, the renewable energy credit
8 procurements, Adjustable Block solar program, and
9 community renewable generation program shall provide
10 employment opportunities for all segments of the
11 population and workforce, including minority-owned and
12 female-owned business enterprises, and shall not,
13 consistent with State and federal law, discriminate based
14 on race or socioeconomic status.
15 (d) Clean coal portfolio standard.
16 (1) The procurement plans shall include electricity
17 generated using clean coal. Each utility shall enter into
18 one or more sourcing agreements with the initial clean
19 coal facility, as provided in paragraph (3) of this
20 subsection (d), covering electricity generated by the
21 initial clean coal facility representing at least 5% of
22 each utility's total supply to serve the load of eligible
23 retail customers in 2015 and each year thereafter, as
24 described in paragraph (3) of this subsection (d), subject
25 to the limits specified in paragraph (2) of this
26 subsection (d). It is the goal of the State that by January

HB2640- 101 -LRB102 13765 SPS 19115 b
1 1, 2025, 25% of the electricity used in the State shall be
2 generated by cost-effective clean coal facilities. For
3 purposes of this subsection (d), "cost-effective" means
4 that the expenditures pursuant to such sourcing agreements
5 do not cause the limit stated in paragraph (2) of this
6 subsection (d) to be exceeded and do not exceed cost-based
7 benchmarks, which shall be developed to assess all
8 expenditures pursuant to such sourcing agreements covering
9 electricity generated by clean coal facilities, other than
10 the initial clean coal facility, by the procurement
11 administrator, in consultation with the Commission staff,
12 Agency staff, and the procurement monitor and shall be
13 subject to Commission review and approval.
14 A utility party to a sourcing agreement shall
15 immediately retire any emission credits that it receives
16 in connection with the electricity covered by such
17 agreement.
18 Utilities shall maintain adequate records documenting
19 the purchases under the sourcing agreement to comply with
20 this subsection (d) and shall file an accounting with the
21 load forecast that must be filed with the Agency by July 15
22 of each year, in accordance with subsection (d) of Section
23 16-111.5 of the Public Utilities Act.
24 A utility shall be deemed to have complied with the
25 clean coal portfolio standard specified in this subsection
26 (d) if the utility enters into a sourcing agreement as

HB2640- 102 -LRB102 13765 SPS 19115 b
1 required by this subsection (d).
2 (2) For purposes of this subsection (d), the required
3 execution of sourcing agreements with the initial clean
4 coal facility for a particular year shall be measured as a
5 percentage of the actual amount of electricity
6 (megawatt-hours) supplied by the electric utility to
7 eligible retail customers in the planning year ending
8 immediately prior to the agreement's execution. For
9 purposes of this subsection (d), the amount paid per
10 kilowatthour means the total amount paid for electric
11 service expressed on a per kilowatthour basis. For
12 purposes of this subsection (d), the total amount paid for
13 electric service includes without limitation amounts paid
14 for supply, transmission, distribution, surcharges and
15 add-on taxes.
16 Notwithstanding the requirements of this subsection
17 (d), the total amount paid under sourcing agreements with
18 clean coal facilities pursuant to the procurement plan for
19 any given year shall be reduced by an amount necessary to
20 limit the annual estimated average net increase due to the
21 costs of these resources included in the amounts paid by
22 eligible retail customers in connection with electric
23 service to:
24 (A) in 2010, no more than 0.5% of the amount paid
25 per kilowatthour by those customers during the year
26 ending May 31, 2009;

HB2640- 103 -LRB102 13765 SPS 19115 b
1 (B) in 2011, the greater of an additional 0.5% of
2 the amount paid per kilowatthour by those customers
3 during the year ending May 31, 2010 or 1% of the amount
4 paid per kilowatthour by those customers during the
5 year ending May 31, 2009;
6 (C) in 2012, the greater of an additional 0.5% of
7 the amount paid per kilowatthour by those customers
8 during the year ending May 31, 2011 or 1.5% of the
9 amount paid per kilowatthour by those customers during
10 the year ending May 31, 2009;
11 (D) in 2013, the greater of an additional 0.5% of
12 the amount paid per kilowatthour by those customers
13 during the year ending May 31, 2012 or 2% of the amount
14 paid per kilowatthour by those customers during the
15 year ending May 31, 2009; and
16 (E) thereafter, the total amount paid under
17 sourcing agreements with clean coal facilities
18 pursuant to the procurement plan for any single year
19 shall be reduced by an amount necessary to limit the
20 estimated average net increase due to the cost of
21 these resources included in the amounts paid by
22 eligible retail customers in connection with electric
23 service to no more than the greater of (i) 2.015% of
24 the amount paid per kilowatthour by those customers
25 during the year ending May 31, 2009 or (ii) the
26 incremental amount per kilowatthour paid for these

HB2640- 104 -LRB102 13765 SPS 19115 b
1 resources in 2013. These requirements may be altered
2 only as provided by statute.
3 No later than June 30, 2015, the Commission shall
4 review the limitation on the total amount paid under
5 sourcing agreements, if any, with clean coal facilities
6 pursuant to this subsection (d) and report to the General
7 Assembly its findings as to whether that limitation unduly
8 constrains the amount of electricity generated by
9 cost-effective clean coal facilities that is covered by
10 sourcing agreements.
11 (3) Initial clean coal facility. In order to promote
12 development of clean coal facilities in Illinois, each
13 electric utility subject to this Section shall execute a
14 sourcing agreement to source electricity from a proposed
15 clean coal facility in Illinois (the "initial clean coal
16 facility") that will have a nameplate capacity of at least
17 500 MW when commercial operation commences, that has a
18 final Clean Air Act permit on June 1, 2009 (the effective
19 date of Public Act 95-1027), and that will meet the
20 definition of clean coal facility in Section 1-10 of this
21 Act when commercial operation commences. The sourcing
22 agreements with this initial clean coal facility shall be
23 subject to both approval of the initial clean coal
24 facility by the General Assembly and satisfaction of the
25 requirements of paragraph (4) of this subsection (d) and
26 shall be executed within 90 days after any such approval

HB2640- 105 -LRB102 13765 SPS 19115 b
1 by the General Assembly. The Agency and the Commission
2 shall have authority to inspect all books and records
3 associated with the initial clean coal facility during the
4 term of such a sourcing agreement. A utility's sourcing
5 agreement for electricity produced by the initial clean
6 coal facility shall include:
7 (A) a formula contractual price (the "contract
8 price") approved pursuant to paragraph (4) of this
9 subsection (d), which shall:
10 (i) be determined using a cost of service
11 methodology employing either a level or deferred
12 capital recovery component, based on a capital
13 structure consisting of 45% equity and 55% debt,
14 and a return on equity as may be approved by the
15 Federal Energy Regulatory Commission, which in any
16 case may not exceed the lower of 11.5% or the rate
17 of return approved by the General Assembly
18 pursuant to paragraph (4) of this subsection (d);
19 and
20 (ii) provide that all miscellaneous net
21 revenue, including but not limited to net revenue
22 from the sale of emission allowances, if any,
23 substitute natural gas, if any, grants or other
24 support provided by the State of Illinois or the
25 United States Government, firm transmission
26 rights, if any, by-products produced by the

HB2640- 106 -LRB102 13765 SPS 19115 b
1 facility, energy or capacity derived from the
2 facility and not covered by a sourcing agreement
3 pursuant to paragraph (3) of this subsection (d)
4 or item (5) of subsection (d) of Section 16-115 of
5 the Public Utilities Act, whether generated from
6 the synthesis gas derived from coal, from SNG, or
7 from natural gas, shall be credited against the
8 revenue requirement for this initial clean coal
9 facility;
10 (B) power purchase provisions, which shall:
11 (i) provide that the utility party to such
12 sourcing agreement shall pay the contract price
13 for electricity delivered under such sourcing
14 agreement;
15 (ii) require delivery of electricity to the
16 regional transmission organization market of the
17 utility that is party to such sourcing agreement;
18 (iii) require the utility party to such
19 sourcing agreement to buy from the initial clean
20 coal facility in each hour an amount of energy
21 equal to all clean coal energy made available from
22 the initial clean coal facility during such hour
23 times a fraction, the numerator of which is such
24 utility's retail market sales of electricity
25 (expressed in kilowatthours sold) in the State
26 during the prior calendar month and the

HB2640- 107 -LRB102 13765 SPS 19115 b
1 denominator of which is the total retail market
2 sales of electricity (expressed in kilowatthours
3 sold) in the State by utilities during such prior
4 month and the sales of electricity (expressed in
5 kilowatthours sold) in the State by alternative
6 retail electric suppliers during such prior month
7 that are subject to the requirements of this
8 subsection (d) and paragraph (5) of subsection (d)
9 of Section 16-115 of the Public Utilities Act,
10 provided that the amount purchased by the utility
11 in any year will be limited by paragraph (2) of
12 this subsection (d); and
13 (iv) be considered pre-existing contracts in
14 such utility's procurement plans for eligible
15 retail customers;
16 (C) contract for differences provisions, which
17 shall:
18 (i) require the utility party to such sourcing
19 agreement to contract with the initial clean coal
20 facility in each hour with respect to an amount of
21 energy equal to all clean coal energy made
22 available from the initial clean coal facility
23 during such hour times a fraction, the numerator
24 of which is such utility's retail market sales of
25 electricity (expressed in kilowatthours sold) in
26 the utility's service territory in the State

HB2640- 108 -LRB102 13765 SPS 19115 b
1 during the prior calendar month and the
2 denominator of which is the total retail market
3 sales of electricity (expressed in kilowatthours
4 sold) in the State by utilities during such prior
5 month and the sales of electricity (expressed in
6 kilowatthours sold) in the State by alternative
7 retail electric suppliers during such prior month
8 that are subject to the requirements of this
9 subsection (d) and paragraph (5) of subsection (d)
10 of Section 16-115 of the Public Utilities Act,
11 provided that the amount paid by the utility in
12 any year will be limited by paragraph (2) of this
13 subsection (d);
14 (ii) provide that the utility's payment
15 obligation in respect of the quantity of
16 electricity determined pursuant to the preceding
17 clause (i) shall be limited to an amount equal to
18 (1) the difference between the contract price
19 determined pursuant to subparagraph (A) of
20 paragraph (3) of this subsection (d) and the
21 day-ahead price for electricity delivered to the
22 regional transmission organization market of the
23 utility that is party to such sourcing agreement
24 (or any successor delivery point at which such
25 utility's supply obligations are financially
26 settled on an hourly basis) (the "reference

HB2640- 109 -LRB102 13765 SPS 19115 b
1 price") on the day preceding the day on which the
2 electricity is delivered to the initial clean coal
3 facility busbar, multiplied by (2) the quantity of
4 electricity determined pursuant to the preceding
5 clause (i); and
6 (iii) not require the utility to take physical
7 delivery of the electricity produced by the
8 facility;
9 (D) general provisions, which shall:
10 (i) specify a term of no more than 30 years,
11 commencing on the commercial operation date of the
12 facility;
13 (ii) provide that utilities shall maintain
14 adequate records documenting purchases under the
15 sourcing agreements entered into to comply with
16 this subsection (d) and shall file an accounting
17 with the load forecast that must be filed with the
18 Agency by July 15 of each year, in accordance with
19 subsection (d) of Section 16-111.5 of the Public
20 Utilities Act;
21 (iii) provide that all costs associated with
22 the initial clean coal facility will be
23 periodically reported to the Federal Energy
24 Regulatory Commission and to purchasers in
25 accordance with applicable laws governing
26 cost-based wholesale power contracts;

HB2640- 110 -LRB102 13765 SPS 19115 b
1 (iv) permit the Illinois Power Agency to
2 assume ownership of the initial clean coal
3 facility, without monetary consideration and
4 otherwise on reasonable terms acceptable to the
5 Agency, if the Agency so requests no less than 3
6 years prior to the end of the stated contract
7 term;
8 (v) require the owner of the initial clean
9 coal facility to provide documentation to the
10 Commission each year, starting in the facility's
11 first year of commercial operation, accurately
12 reporting the quantity of carbon emissions from
13 the facility that have been captured and
14 sequestered and report any quantities of carbon
15 released from the site or sites at which carbon
16 emissions were sequestered in prior years, based
17 on continuous monitoring of such sites. If, in any
18 year after the first year of commercial operation,
19 the owner of the facility fails to demonstrate
20 that the initial clean coal facility captured and
21 sequestered at least 50% of the total carbon
22 emissions that the facility would otherwise emit
23 or that sequestration of emissions from prior
24 years has failed, resulting in the release of
25 carbon dioxide into the atmosphere, the owner of
26 the facility must offset excess emissions. Any

HB2640- 111 -LRB102 13765 SPS 19115 b
1 such carbon offsets must be permanent, additional,
2 verifiable, real, located within the State of
3 Illinois, and legally and practicably enforceable.
4 The cost of such offsets for the facility that are
5 not recoverable shall not exceed $15 million in
6 any given year. No costs of any such purchases of
7 carbon offsets may be recovered from a utility or
8 its customers. All carbon offsets purchased for
9 this purpose and any carbon emission credits
10 associated with sequestration of carbon from the
11 facility must be permanently retired. The initial
12 clean coal facility shall not forfeit its
13 designation as a clean coal facility if the
14 facility fails to fully comply with the applicable
15 carbon sequestration requirements in any given
16 year, provided the requisite offsets are
17 purchased. However, the Attorney General, on
18 behalf of the People of the State of Illinois, may
19 specifically enforce the facility's sequestration
20 requirement and the other terms of this contract
21 provision. Compliance with the sequestration
22 requirements and offset purchase requirements
23 specified in paragraph (3) of this subsection (d)
24 shall be reviewed annually by an independent
25 expert retained by the owner of the initial clean
26 coal facility, with the advance written approval

HB2640- 112 -LRB102 13765 SPS 19115 b
1 of the Attorney General. The Commission may, in
2 the course of the review specified in item (vii),
3 reduce the allowable return on equity for the
4 facility if the facility willfully fails to comply
5 with the carbon capture and sequestration
6 requirements set forth in this item (v);
7 (vi) include limits on, and accordingly
8 provide for modification of, the amount the
9 utility is required to source under the sourcing
10 agreement consistent with paragraph (2) of this
11 subsection (d);
12 (vii) require Commission review: (1) to
13 determine the justness, reasonableness, and
14 prudence of the inputs to the formula referenced
15 in subparagraphs (A)(i) through (A)(iii) of
16 paragraph (3) of this subsection (d), prior to an
17 adjustment in those inputs including, without
18 limitation, the capital structure and return on
19 equity, fuel costs, and other operations and
20 maintenance costs and (2) to approve the costs to
21 be passed through to customers under the sourcing
22 agreement by which the utility satisfies its
23 statutory obligations. Commission review shall
24 occur no less than every 3 years, regardless of
25 whether any adjustments have been proposed, and
26 shall be completed within 9 months;

HB2640- 113 -LRB102 13765 SPS 19115 b
1 (viii) limit the utility's obligation to such
2 amount as the utility is allowed to recover
3 through tariffs filed with the Commission,
4 provided that neither the clean coal facility nor
5 the utility waives any right to assert federal
6 pre-emption or any other argument in response to a
7 purported disallowance of recovery costs;
8 (ix) limit the utility's or alternative retail
9 electric supplier's obligation to incur any
10 liability until such time as the facility is in
11 commercial operation and generating power and
12 energy and such power and energy is being
13 delivered to the facility busbar;
14 (x) provide that the owner or owners of the
15 initial clean coal facility, which is the
16 counterparty to such sourcing agreement, shall
17 have the right from time to time to elect whether
18 the obligations of the utility party thereto shall
19 be governed by the power purchase provisions or
20 the contract for differences provisions;
21 (xi) append documentation showing that the
22 formula rate and contract, insofar as they relate
23 to the power purchase provisions, have been
24 approved by the Federal Energy Regulatory
25 Commission pursuant to Section 205 of the Federal
26 Power Act;

HB2640- 114 -LRB102 13765 SPS 19115 b
1 (xii) provide that any changes to the terms of
2 the contract, insofar as such changes relate to
3 the power purchase provisions, are subject to
4 review under the public interest standard applied
5 by the Federal Energy Regulatory Commission
6 pursuant to Sections 205 and 206 of the Federal
7 Power Act; and
8 (xiii) conform with customary lender
9 requirements in power purchase agreements used as
10 the basis for financing non-utility generators.
11 (4) Effective date of sourcing agreements with the
12 initial clean coal facility. Any proposed sourcing
13 agreement with the initial clean coal facility shall not
14 become effective unless the following reports are prepared
15 and submitted and authorizations and approvals obtained:
16 (i) Facility cost report. The owner of the initial
17 clean coal facility shall submit to the Commission,
18 the Agency, and the General Assembly a front-end
19 engineering and design study, a facility cost report,
20 method of financing (including but not limited to
21 structure and associated costs), and an operating and
22 maintenance cost quote for the facility (collectively
23 "facility cost report"), which shall be prepared in
24 accordance with the requirements of this paragraph (4)
25 of subsection (d) of this Section, and shall provide
26 the Commission and the Agency access to the work

HB2640- 115 -LRB102 13765 SPS 19115 b
1 papers, relied upon documents, and any other backup
2 documentation related to the facility cost report.
3 (ii) Commission report. Within 6 months following
4 receipt of the facility cost report, the Commission,
5 in consultation with the Agency, shall submit a report
6 to the General Assembly setting forth its analysis of
7 the facility cost report. Such report shall include,
8 but not be limited to, a comparison of the costs
9 associated with electricity generated by the initial
10 clean coal facility to the costs associated with
11 electricity generated by other types of generation
12 facilities, an analysis of the rate impacts on
13 residential and small business customers over the life
14 of the sourcing agreements, and an analysis of the
15 likelihood that the initial clean coal facility will
16 commence commercial operation by and be delivering
17 power to the facility's busbar by 2016. To assist in
18 the preparation of its report, the Commission, in
19 consultation with the Agency, may hire one or more
20 experts or consultants, the costs of which shall be
21 paid for by the owner of the initial clean coal
22 facility. The Commission and Agency may begin the
23 process of selecting such experts or consultants prior
24 to receipt of the facility cost report.
25 (iii) General Assembly approval. The proposed
26 sourcing agreements shall not take effect unless,

HB2640- 116 -LRB102 13765 SPS 19115 b
1 based on the facility cost report and the Commission's
2 report, the General Assembly enacts authorizing
3 legislation approving (A) the projected price, stated
4 in cents per kilowatthour, to be charged for
5 electricity generated by the initial clean coal
6 facility, (B) the projected impact on residential and
7 small business customers' bills over the life of the
8 sourcing agreements, and (C) the maximum allowable
9 return on equity for the project; and
10 (iv) Commission review. If the General Assembly
11 enacts authorizing legislation pursuant to
12 subparagraph (iii) approving a sourcing agreement, the
13 Commission shall, within 90 days of such enactment,
14 complete a review of such sourcing agreement. During
15 such time period, the Commission shall implement any
16 directive of the General Assembly, resolve any
17 disputes between the parties to the sourcing agreement
18 concerning the terms of such agreement, approve the
19 form of such agreement, and issue an order finding
20 that the sourcing agreement is prudent and reasonable.
21 The facility cost report shall be prepared as follows:
22 (A) The facility cost report shall be prepared by
23 duly licensed engineering and construction firms
24 detailing the estimated capital costs payable to one
25 or more contractors or suppliers for the engineering,
26 procurement and construction of the components

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1 comprising the initial clean coal facility and the
2 estimated costs of operation and maintenance of the
3 facility. The facility cost report shall include:
4 (i) an estimate of the capital cost of the
5 core plant based on one or more front end
6 engineering and design studies for the
7 gasification island and related facilities. The
8 core plant shall include all civil, structural,
9 mechanical, electrical, control, and safety
10 systems.
11 (ii) an estimate of the capital cost of the
12 balance of the plant, including any capital costs
13 associated with sequestration of carbon dioxide
14 emissions and all interconnects and interfaces
15 required to operate the facility, such as
16 transmission of electricity, construction or
17 backfeed power supply, pipelines to transport
18 substitute natural gas or carbon dioxide, potable
19 water supply, natural gas supply, water supply,
20 water discharge, landfill, access roads, and coal
21 delivery.
22 The quoted construction costs shall be expressed
23 in nominal dollars as of the date that the quote is
24 prepared and shall include capitalized financing costs
25 during construction, taxes, insurance, and other
26 owner's costs, and an assumed escalation in materials

HB2640- 118 -LRB102 13765 SPS 19115 b
1 and labor beyond the date as of which the construction
2 cost quote is expressed.
3 (B) The front end engineering and design study for
4 the gasification island and the cost study for the
5 balance of plant shall include sufficient design work
6 to permit quantification of major categories of
7 materials, commodities and labor hours, and receipt of
8 quotes from vendors of major equipment required to
9 construct and operate the clean coal facility.
10 (C) The facility cost report shall also include an
11 operating and maintenance cost quote that will provide
12 the estimated cost of delivered fuel, personnel,
13 maintenance contracts, chemicals, catalysts,
14 consumables, spares, and other fixed and variable
15 operations and maintenance costs. The delivered fuel
16 cost estimate will be provided by a recognized third
17 party expert or experts in the fuel and transportation
18 industries. The balance of the operating and
19 maintenance cost quote, excluding delivered fuel
20 costs, will be developed based on the inputs provided
21 by duly licensed engineering and construction firms
22 performing the construction cost quote, potential
23 vendors under long-term service agreements and plant
24 operating agreements, or recognized third party plant
25 operator or operators.
26 The operating and maintenance cost quote

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1 (including the cost of the front end engineering and
2 design study) shall be expressed in nominal dollars as
3 of the date that the quote is prepared and shall
4 include taxes, insurance, and other owner's costs, and
5 an assumed escalation in materials and labor beyond
6 the date as of which the operating and maintenance
7 cost quote is expressed.
8 (D) The facility cost report shall also include an
9 analysis of the initial clean coal facility's ability
10 to deliver power and energy into the applicable
11 regional transmission organization markets and an
12 analysis of the expected capacity factor for the
13 initial clean coal facility.
14 (E) Amounts paid to third parties unrelated to the
15 owner or owners of the initial clean coal facility to
16 prepare the core plant construction cost quote,
17 including the front end engineering and design study,
18 and the operating and maintenance cost quote will be
19 reimbursed through Coal Development Bonds.
20 (5) Re-powering and retrofitting coal-fired power
21 plants previously owned by Illinois utilities to qualify
22 as clean coal facilities. During the 2009 procurement
23 planning process and thereafter, the Agency and the
24 Commission shall consider sourcing agreements covering
25 electricity generated by power plants that were previously
26 owned by Illinois utilities and that have been or will be

HB2640- 120 -LRB102 13765 SPS 19115 b
1 converted into clean coal facilities, as defined by
2 Section 1-10 of this Act. Pursuant to such procurement
3 planning process, the owners of such facilities may
4 propose to the Agency sourcing agreements with utilities
5 and alternative retail electric suppliers required to
6 comply with subsection (d) of this Section and item (5) of
7 subsection (d) of Section 16-115 of the Public Utilities
8 Act, covering electricity generated by such facilities. In
9 the case of sourcing agreements that are power purchase
10 agreements, the contract price for electricity sales shall
11 be established on a cost of service basis. In the case of
12 sourcing agreements that are contracts for differences,
13 the contract price from which the reference price is
14 subtracted shall be established on a cost of service
15 basis. The Agency and the Commission may approve any such
16 utility sourcing agreements that do not exceed cost-based
17 benchmarks developed by the procurement administrator, in
18 consultation with the Commission staff, Agency staff and
19 the procurement monitor, subject to Commission review and
20 approval. The Commission shall have authority to inspect
21 all books and records associated with these clean coal
22 facilities during the term of any such contract.
23 (6) Costs incurred under this subsection (d) or
24 pursuant to a contract entered into under this subsection
25 (d) shall be deemed prudently incurred and reasonable in
26 amount and the electric utility shall be entitled to full

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1 cost recovery pursuant to the tariffs filed with the
2 Commission.
3 (d-5) Zero emission standard.
4 (1) Beginning with the delivery year commencing on
5 June 1, 2017, the Agency shall, for electric utilities
6 that serve at least 100,000 retail customers in this
7 State, procure contracts with zero emission facilities
8 that are reasonably capable of generating cost-effective
9 zero emission credits in an amount approximately equal to
10 16% of the actual amount of electricity delivered by each
11 electric utility to retail customers in the State during
12 calendar year 2014. For an electric utility serving fewer
13 than 100,000 retail customers in this State that
14 requested, under Section 16-111.5 of the Public Utilities
15 Act, that the Agency procure power and energy for all or a
16 portion of the utility's Illinois load for the delivery
17 year commencing June 1, 2016, the Agency shall procure
18 contracts with zero emission facilities that are
19 reasonably capable of generating cost-effective zero
20 emission credits in an amount approximately equal to 16%
21 of the portion of power and energy to be procured by the
22 Agency for the utility. The duration of the contracts
23 procured under this subsection (d-5) shall be for a term
24 of 10 years ending May 31, 2027. The quantity of zero
25 emission credits to be procured under the contracts shall
26 be all of the zero emission credits generated by the zero

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1 emission facility in each delivery year; however, if the
2 zero emission facility is owned by more than one entity,
3 then the quantity of zero emission credits to be procured
4 under the contracts shall be the amount of zero emission
5 credits that are generated from the portion of the zero
6 emission facility that is owned by the winning supplier.
7 The 16% value identified in this paragraph (1) is the
8 average of the percentage targets in subparagraph (B) of
9 paragraph (1) of subsection (c) of this Section for the 5
10 delivery years beginning June 1, 2017.
11 The procurement process shall be subject to the
12 following provisions:
13 (A) Those zero emission facilities that intend to
14 participate in the procurement shall submit to the
15 Agency the following eligibility information for each
16 zero emission facility on or before the date
17 established by the Agency:
18 (i) the in-service date and remaining useful
19 life of the zero emission facility;
20 (ii) the amount of power generated annually
21 for each of the years 2005 through 2015, and the
22 projected zero emission credits to be generated
23 over the remaining useful life of the zero
24 emission facility, which shall be used to
25 determine the capability of each facility;
26 (iii) the annual zero emission facility cost

HB2640- 123 -LRB102 13765 SPS 19115 b
1 projections, expressed on a per megawatthour
2 basis, over the next 6 delivery years, which shall
3 include the following: operation and maintenance
4 expenses; fully allocated overhead costs, which
5 shall be allocated using the methodology developed
6 by the Institute for Nuclear Power Operations;
7 fuel expenditures; non-fuel capital expenditures;
8 spent fuel expenditures; a return on working
9 capital; the cost of operational and market risks
10 that could be avoided by ceasing operation; and
11 any other costs necessary for continued
12 operations, provided that "necessary" means, for
13 purposes of this item (iii), that the costs could
14 reasonably be avoided only by ceasing operations
15 of the zero emission facility; and
16 (iv) a commitment to continue operating, for
17 the duration of the contract or contracts executed
18 under the procurement held under this subsection
19 (d-5), the zero emission facility that produces
20 the zero emission credits to be procured in the
21 procurement.
22 The information described in item (iii) of this
23 subparagraph (A) may be submitted on a confidential
24 basis and shall be treated and maintained by the
25 Agency, the procurement administrator, and the
26 Commission as confidential and proprietary and exempt

HB2640- 124 -LRB102 13765 SPS 19115 b
1 from disclosure under subparagraphs (a) and (g) of
2 paragraph (1) of Section 7 of the Freedom of
3 Information Act. The Office of Attorney General shall
4 have access to, and maintain the confidentiality of,
5 such information pursuant to Section 6.5 of the
6 Attorney General Act.
7 (B) The price for each zero emission credit
8 procured under this subsection (d-5) for each delivery
9 year shall be in an amount that equals the Social Cost
10 of Carbon, expressed on a price per megawatthour
11 basis. However, to ensure that the procurement remains
12 affordable to retail customers in this State if
13 electricity prices increase, the price in an
14 applicable delivery year shall be reduced below the
15 Social Cost of Carbon by the amount ("Price
16 Adjustment") by which the market price index for the
17 applicable delivery year exceeds the baseline market
18 price index for the consecutive 12-month period ending
19 May 31, 2016. If the Price Adjustment is greater than
20 or equal to the Social Cost of Carbon in an applicable
21 delivery year, then no payments shall be due in that
22 delivery year. The components of this calculation are
23 defined as follows:
24 (i) Social Cost of Carbon: The Social Cost of
25 Carbon is $16.50 per megawatthour, which is based
26 on the U.S. Interagency Working Group on Social

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1 Cost of Carbon's price in the August 2016
2 Technical Update using a 3% discount rate,
3 adjusted for inflation for each year of the
4 program. Beginning with the delivery year
5 commencing June 1, 2023, the price per
6 megawatthour shall increase by $1 per
7 megawatthour, and continue to increase by an
8 additional $1 per megawatthour each delivery year
9 thereafter.
10 (ii) Baseline market price index: The baseline
11 market price index for the consecutive 12-month
12 period ending May 31, 2016 is $31.40 per
13 megawatthour, which is based on the sum of (aa)
14 the average day-ahead energy price across all
15 hours of such 12-month period at the PJM
16 Interconnection LLC Northern Illinois Hub, (bb)
17 50% multiplied by the Base Residual Auction, or
18 its successor, capacity price for the rest of the
19 RTO zone group determined by PJM Interconnection
20 LLC, divided by 24 hours per day, and (cc) 50%
21 multiplied by the Planning Resource Auction, or
22 its successor, capacity price for Zone 4
23 determined by the Midcontinent Independent System
24 Operator, Inc., divided by 24 hours per day.
25 (iii) Market price index: The market price
26 index for a delivery year shall be the sum of

HB2640- 126 -LRB102 13765 SPS 19115 b
1 projected energy prices and projected capacity
2 prices determined as follows:
3 (aa) Projected energy prices: the
4 projected energy prices for the applicable
5 delivery year shall be calculated once for the
6 year using the forward market price for the
7 PJM Interconnection, LLC Northern Illinois
8 Hub. The forward market price shall be
9 calculated as follows: the energy forward
10 prices for each month of the applicable
11 delivery year averaged for each trade date
12 during the calendar year immediately preceding
13 that delivery year to produce a single energy
14 forward price for the delivery year. The
15 forward market price calculation shall use
16 data published by the Intercontinental
17 Exchange, or its successor.
18 (bb) Projected capacity prices:
19 (I) For the delivery years commencing
20 June 1, 2017, June 1, 2018, and June 1,
21 2019, the projected capacity price shall
22 be equal to the sum of (1) 50% multiplied
23 by the Base Residual Auction, or its
24 successor, price for the rest of the RTO
25 zone group as determined by PJM
26 Interconnection LLC, divided by 24 hours

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1 per day and, (2) 50% multiplied by the
2 resource auction price determined in the
3 resource auction administered by the
4 Midcontinent Independent System Operator,
5 Inc., in which the largest percentage of
6 load cleared for Local Resource Zone 4,
7 divided by 24 hours per day, and where
8 such price is determined by the
9 Midcontinent Independent System Operator,
10 Inc.
11 (II) For the delivery year commencing
12 June 1, 2020, and each year thereafter,
13 the projected capacity price shall be
14 equal to the sum of (1) 50% multiplied by
15 the Base Residual Auction, or its
16 successor, price for the ComEd zone as
17 determined by PJM Interconnection LLC,
18 divided by 24 hours per day, and (2) 50%
19 multiplied by the resource auction price
20 determined in the resource auction
21 administered by the Midcontinent
22 Independent System Operator, Inc., in
23 which the largest percentage of load
24 cleared for Local Resource Zone 4, divided
25 by 24 hours per day, and where such price
26 is determined by the Midcontinent

HB2640- 128 -LRB102 13765 SPS 19115 b
1 Independent System Operator, Inc.
2 For purposes of this subsection (d-5):
3 "Rest of the RTO" and "ComEd Zone" shall have
4 the meaning ascribed to them by PJM
5 Interconnection, LLC.
6 "RTO" means regional transmission
7 organization.
8 (C) No later than 45 days after June 1, 2017 (the
9 effective date of Public Act 99-906), the Agency shall
10 publish its proposed zero emission standard
11 procurement plan. The plan shall be consistent with
12 the provisions of this paragraph (1) and shall provide
13 that winning bids shall be selected based on public
14 interest criteria that include, but are not limited
15 to, minimizing carbon dioxide emissions that result
16 from electricity consumed in Illinois and minimizing
17 sulfur dioxide, nitrogen oxide, and particulate matter
18 emissions that adversely affect the citizens of this
19 State. In particular, the selection of winning bids
20 shall take into account the incremental environmental
21 benefits resulting from the procurement, such as any
22 existing environmental benefits that are preserved by
23 the procurements held under Public Act 99-906 and
24 would cease to exist if the procurements were not
25 held, including the preservation of zero emission
26 facilities. The plan shall also describe in detail how

HB2640- 129 -LRB102 13765 SPS 19115 b
1 each public interest factor shall be considered and
2 weighted in the bid selection process to ensure that
3 the public interest criteria are applied to the
4 procurement and given full effect.
5 For purposes of developing the plan, the Agency
6 shall consider any reports issued by a State agency,
7 board, or commission under House Resolution 1146 of
8 the 98th General Assembly and paragraph (4) of
9 subsection (d) of this Section, as well as publicly
10 available analyses and studies performed by or for
11 regional transmission organizations that serve the
12 State and their independent market monitors.
13 Upon publishing of the zero emission standard
14 procurement plan, copies of the plan shall be posted
15 and made publicly available on the Agency's website.
16 All interested parties shall have 10 days following
17 the date of posting to provide comment to the Agency on
18 the plan. All comments shall be posted to the Agency's
19 website. Following the end of the comment period, but
20 no more than 60 days later than June 1, 2017 (the
21 effective date of Public Act 99-906), the Agency shall
22 revise the plan as necessary based on the comments
23 received and file its zero emission standard
24 procurement plan with the Commission.
25 If the Commission determines that the plan will
26 result in the procurement of cost-effective zero

HB2640- 130 -LRB102 13765 SPS 19115 b
1 emission credits, then the Commission shall, after
2 notice and hearing, but no later than 45 days after the
3 Agency filed the plan, approve the plan or approve
4 with modification. For purposes of this subsection
5 (d-5), "cost effective" means the projected costs of
6 procuring zero emission credits from zero emission
7 facilities do not cause the limit stated in paragraph
8 (2) of this subsection to be exceeded.
9 (C-5) As part of the Commission's review and
10 acceptance or rejection of the procurement results,
11 the Commission shall, in its public notice of
12 successful bidders:
13 (i) identify how the winning bids satisfy the
14 public interest criteria described in subparagraph
15 (C) of this paragraph (1) of minimizing carbon
16 dioxide emissions that result from electricity
17 consumed in Illinois and minimizing sulfur
18 dioxide, nitrogen oxide, and particulate matter
19 emissions that adversely affect the citizens of
20 this State;
21 (ii) specifically address how the selection of
22 winning bids takes into account the incremental
23 environmental benefits resulting from the
24 procurement, including any existing environmental
25 benefits that are preserved by the procurements
26 held under Public Act 99-906 and would have ceased

HB2640- 131 -LRB102 13765 SPS 19115 b
1 to exist if the procurements had not been held,
2 such as the preservation of zero emission
3 facilities;
4 (iii) quantify the environmental benefit of
5 preserving the resources identified in item (ii)
6 of this subparagraph (C-5), including the
7 following:
8 (aa) the value of avoided greenhouse gas
9 emissions measured as the product of the zero
10 emission facilities' output over the contract
11 term multiplied by the U.S. Environmental
12 Protection Agency eGrid subregion carbon
13 dioxide emission rate and the U.S. Interagency
14 Working Group on Social Cost of Carbon's price
15 in the August 2016 Technical Update using a 3%
16 discount rate, adjusted for inflation for each
17 delivery year; and
18 (bb) the costs of replacement with other
19 zero carbon dioxide resources, including wind
20 and photovoltaic, based upon the simple
21 average of the following:
22 (I) the price, or if there is more
23 than one price, the average of the prices,
24 paid for renewable energy credits from new
25 utility-scale wind projects in the
26 procurement events specified in item (i)

HB2640- 132 -LRB102 13765 SPS 19115 b
1 of subparagraph (G) of paragraph (1) of
2 subsection (c) of this Section; and
3 (II) the price, or if there is more
4 than one price, the average of the prices,
5 paid for renewable energy credits from new
6 utility-scale solar projects and
7 brownfield site photovoltaic projects in
8 the procurement events specified in item
9 (ii) of subparagraph (G) of paragraph (1)
10 of subsection (c) of this Section and,
11 after January 1, 2015, renewable energy
12 credits from photovoltaic distributed
13 generation projects in procurement events
14 held under subsection (c) of this Section.
15 Each utility shall enter into binding contractual
16 arrangements with the winning suppliers.
17 The procurement described in this subsection
18 (d-5), including, but not limited to, the execution of
19 all contracts procured, shall be completed no later
20 than May 10, 2017. Based on the effective date of
21 Public Act 99-906, the Agency and Commission may, as
22 appropriate, modify the various dates and timelines
23 under this subparagraph and subparagraphs (C) and (D)
24 of this paragraph (1). The procurement and plan
25 approval processes required by this subsection (d-5)
26 shall be conducted in conjunction with the procurement

HB2640- 133 -LRB102 13765 SPS 19115 b
1 and plan approval processes required by subsection (c)
2 of this Section and Section 16-111.5 of the Public
3 Utilities Act, to the extent practicable.
4 Notwithstanding whether a procurement event is
5 conducted under Section 16-111.5 of the Public
6 Utilities Act, the Agency shall immediately initiate a
7 procurement process on June 1, 2017 (the effective
8 date of Public Act 99-906).
9 (D) Following the procurement event described in
10 this paragraph (1) and consistent with subparagraph
11 (B) of this paragraph (1), the Agency shall calculate
12 the payments to be made under each contract for the
13 next delivery year based on the market price index for
14 that delivery year. The Agency shall publish the
15 payment calculations no later than May 25, 2017 and
16 every May 25 thereafter.
17 (E) Notwithstanding the requirements of this
18 subsection (d-5), the contracts executed under this
19 subsection (d-5) shall provide that the zero emission
20 facility may, as applicable, suspend or terminate
21 performance under the contracts in the following
22 instances:
23 (i) A zero emission facility shall be excused
24 from its performance under the contract for any
25 cause beyond the control of the resource,
26 including, but not restricted to, acts of God,

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1 flood, drought, earthquake, storm, fire,
2 lightning, epidemic, war, riot, civil disturbance
3 or disobedience, labor dispute, labor or material
4 shortage, sabotage, acts of public enemy,
5 explosions, orders, regulations or restrictions
6 imposed by governmental, military, or lawfully
7 established civilian authorities, which, in any of
8 the foregoing cases, by exercise of commercially
9 reasonable efforts the zero emission facility
10 could not reasonably have been expected to avoid,
11 and which, by the exercise of commercially
12 reasonable efforts, it has been unable to
13 overcome. In such event, the zero emission
14 facility shall be excused from performance for the
15 duration of the event, including, but not limited
16 to, delivery of zero emission credits, and no
17 payment shall be due to the zero emission facility
18 during the duration of the event.
19 (ii) A zero emission facility shall be
20 permitted to terminate the contract if legislation
21 is enacted into law by the General Assembly that
22 imposes or authorizes a new tax, special
23 assessment, or fee on the generation of
24 electricity, the ownership or leasehold of a
25 generating unit, or the privilege or occupation of
26 such generation, ownership, or leasehold of

HB2640- 135 -LRB102 13765 SPS 19115 b
1 generation units by a zero emission facility.
2 However, the provisions of this item (ii) do not
3 apply to any generally applicable tax, special
4 assessment or fee, or requirements imposed by
5 federal law.
6 (iii) A zero emission facility shall be
7 permitted to terminate the contract in the event
8 that the resource requires capital expenditures in
9 excess of $40,000,000 that were neither known nor
10 reasonably foreseeable at the time it executed the
11 contract and that a prudent owner or operator of
12 such resource would not undertake.
13 (iv) A zero emission facility shall be
14 permitted to terminate the contract in the event
15 the Nuclear Regulatory Commission terminates the
16 resource's license.
17 (F) If the zero emission facility elects to
18 terminate a contract under subparagraph (E) of this
19 paragraph (1), then the Commission shall reopen the
20 docket in which the Commission approved the zero
21 emission standard procurement plan under subparagraph
22 (C) of this paragraph (1) and, after notice and
23 hearing, enter an order acknowledging the contract
24 termination election if such termination is consistent
25 with the provisions of this subsection (d-5).
26 (2) For purposes of this subsection (d-5), the amount

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1 paid per kilowatthour means the total amount paid for
2 electric service expressed on a per kilowatthour basis.
3 For purposes of this subsection (d-5), the total amount
4 paid for electric service includes, without limitation,
5 amounts paid for supply, transmission, distribution,
6 surcharges, and add-on taxes.
7 Notwithstanding the requirements of this subsection
8 (d-5), the contracts executed under this subsection (d-5)
9 shall provide that the total of zero emission credits
10 procured under a procurement plan shall be subject to the
11 limitations of this paragraph (2). For each delivery year,
12 the contractual volume receiving payments in such year
13 shall be reduced for all retail customers based on the
14 amount necessary to limit the net increase that delivery
15 year to the costs of those credits included in the amounts
16 paid by eligible retail customers in connection with
17 electric service to no more than 1.65% of the amount paid
18 per kilowatthour by eligible retail customers during the
19 year ending May 31, 2009. The result of this computation
20 shall apply to and reduce the procurement for all retail
21 customers, and all those customers shall pay the same
22 single, uniform cents per kilowatthour charge under
23 subsection (k) of Section 16-108 of the Public Utilities
24 Act. To arrive at a maximum dollar amount of zero emission
25 credits to be paid for the particular delivery year, the
26 resulting per kilowatthour amount shall be applied to the

HB2640- 137 -LRB102 13765 SPS 19115 b
1 actual amount of kilowatthours of electricity delivered by
2 the electric utility in the delivery year immediately
3 prior to the procurement, to all retail customers in its
4 service territory. Unpaid contractual volume for any
5 delivery year shall be paid in any subsequent delivery
6 year in which such payments can be made without exceeding
7 the amount specified in this paragraph (2). The
8 calculations required by this paragraph (2) shall be made
9 only once for each procurement plan year. Once the
10 determination as to the amount of zero emission credits to
11 be paid is made based on the calculations set forth in this
12 paragraph (2), no subsequent rate impact determinations
13 shall be made and no adjustments to those contract amounts
14 shall be allowed. All costs incurred under those contracts
15 and in implementing this subsection (d-5) shall be
16 recovered by the electric utility as provided in this
17 Section.
18 No later than June 30, 2019, the Commission shall
19 review the limitation on the amount of zero emission
20 credits procured under this subsection (d-5) and report to
21 the General Assembly its findings as to whether that
22 limitation unduly constrains the procurement of
23 cost-effective zero emission credits.
24 (3) Six years after the execution of a contract under
25 this subsection (d-5), the Agency shall determine whether
26 the actual zero emission credit payments received by the

HB2640- 138 -LRB102 13765 SPS 19115 b
1 supplier over the 6-year period exceed the Average ZEC
2 Payment. In addition, at the end of the term of a contract
3 executed under this subsection (d-5), or at the time, if
4 any, a zero emission facility's contract is terminated
5 under subparagraph (E) of paragraph (1) of this subsection
6 (d-5), then the Agency shall determine whether the actual
7 zero emission credit payments received by the supplier
8 over the term of the contract exceed the Average ZEC
9 Payment, after taking into account any amounts previously
10 credited back to the utility under this paragraph (3). If
11 the Agency determines that the actual zero emission credit
12 payments received by the supplier over the relevant period
13 exceed the Average ZEC Payment, then the supplier shall
14 credit the difference back to the utility. The amount of
15 the credit shall be remitted to the applicable electric
16 utility no later than 120 days after the Agency's
17 determination, which the utility shall reflect as a credit
18 on its retail customer bills as soon as practicable;
19 however, the credit remitted to the utility shall not
20 exceed the total amount of payments received by the
21 facility under its contract.
22 For purposes of this Section, the Average ZEC Payment
23 shall be calculated by multiplying the quantity of zero
24 emission credits delivered under the contract times the
25 average contract price. The average contract price shall
26 be determined by subtracting the amount calculated under

HB2640- 139 -LRB102 13765 SPS 19115 b
1 subparagraph (B) of this paragraph (3) from the amount
2 calculated under subparagraph (A) of this paragraph (3),
3 as follows:
4 (A) The average of the Social Cost of Carbon, as
5 defined in subparagraph (B) of paragraph (1) of this
6 subsection (d-5), during the term of the contract.
7 (B) The average of the market price indices, as
8 defined in subparagraph (B) of paragraph (1) of this
9 subsection (d-5), during the term of the contract,
10 minus the baseline market price index, as defined in
11 subparagraph (B) of paragraph (1) of this subsection
12 (d-5).
13 If the subtraction yields a negative number, then the
14 Average ZEC Payment shall be zero.
15 (4) Cost-effective zero emission credits procured from
16 zero emission facilities shall satisfy the applicable
17 definitions set forth in Section 1-10 of this Act.
18 (5) The electric utility shall retire all zero
19 emission credits used to comply with the requirements of
20 this subsection (d-5).
21 (6) Electric utilities shall be entitled to recover
22 all of the costs associated with the procurement of zero
23 emission credits through an automatic adjustment clause
24 tariff in accordance with subsection (k) and (m) of
25 Section 16-108 of the Public Utilities Act, and the
26 contracts executed under this subsection (d-5) shall

HB2640- 140 -LRB102 13765 SPS 19115 b
1 provide that the utilities' payment obligations under such
2 contracts shall be reduced if an adjustment is required
3 under subsection (m) of Section 16-108 of the Public
4 Utilities Act.
5 (7) This subsection (d-5) shall become inoperative on
6 January 1, 2028.
7 (e) The draft procurement plans are subject to public
8comment, as required by Section 16-111.5 of the Public
9Utilities Act.
10 (f) The Agency shall submit the final procurement plan to
11the Commission. The Agency shall revise a procurement plan if
12the Commission determines that it does not meet the standards
13set forth in Section 16-111.5 of the Public Utilities Act.
14 (g) The Agency shall assess fees to each affected utility
15to recover the costs incurred in preparation of the annual
16procurement plan for the utility.
17 (h) The Agency shall assess fees to each bidder to recover
18the costs incurred in connection with a competitive
19procurement process.
20 (i) A renewable energy credit, carbon emission credit, or
21zero emission credit can only be used once to comply with a
22single portfolio or other standard as set forth in subsection
23(c), subsection (d), or subsection (d-5) of this Section,
24respectively. A renewable energy credit, carbon emission
25credit, or zero emission credit cannot be used to satisfy the
26requirements of more than one standard. If more than one type

HB2640- 141 -LRB102 13765 SPS 19115 b
1of credit is issued for the same megawatt hour of energy, only
2one credit can be used to satisfy the requirements of a single
3standard. After such use, the credit must be retired together
4with any other credits issued for the same megawatt hour of
5energy.
6(Source: P.A. 100-863, eff. 8-14-18; 101-81, eff. 7-12-19;
7101-113, eff. 1-1-20.)
8 Section 20. The Public Utilities Act is amended by
9changing Sections 16-107.5, 16-107.6, 16-108, and 16-111.5 and
10by adding Section 16-107.7 as follows:
11 (220 ILCS 5/16-107.5)
12 Sec. 16-107.5. Net electricity metering.
13 (a) The Legislature finds and declares that a program to
14provide net electricity metering, as defined in this Section,
15for eligible customers can encourage private investment in
16renewable energy resources, stimulate economic growth, enhance
17the continued diversification of Illinois' energy resource
18mix, and protect the Illinois environment. Further, to achieve
19the goal of this Act that robust options for customer-site
20distributed generation continue to thrive in Illinois, the
21General Assembly finds that a smooth, predictable transition
22must be ensured for customers between full net metering at the
23retail electricity rate to the distribution generation rebate
24described in Section 16-107.6.

HB2640- 142 -LRB102 13765 SPS 19115 b
1 (b) As used in this Section, (i) "community renewable
2generation project" shall have the meaning set forth in
3Section 1-10 of the Illinois Power Agency Act; (ii) "eligible
4customer" means a retail customer that owns, hosts, or
5operates, including any third-party owned systems, a solar,
6wind, or other eligible renewable electrical generating
7facility with a rated capacity of not more than 2,000
8kilowatts that is located on the customer's premises and is
9intended primarily to offset the customer's own current or
10future electrical requirements; (iii) "electricity provider"
11means an electric utility or alternative retail electric
12supplier; (iv) "eligible renewable electrical generating
13facility" means a generator, which may include the co-location
14of an energy storage system, that is interconnected under
15rules adopted by the Commission and is powered by solar
16electric energy, wind, dedicated crops grown for electricity
17generation, agricultural residues, untreated and unadulterated
18wood waste, landscape trimmings, livestock manure, anaerobic
19digestion of livestock or food processing waste, fuel cells or
20microturbines powered by renewable fuels, or hydroelectric
21energy; (v) "net electricity metering" (or "net metering")
22means the measurement, during the billing period applicable to
23an eligible customer, of the net amount of electricity
24supplied by an electricity provider to the customer's premises
25or provided to the electricity provider by the customer or
26subscriber; (vi) "subscriber" shall have the meaning as set

HB2640- 143 -LRB102 13765 SPS 19115 b
1forth in Section 1-10 of the Illinois Power Agency Act; and
2(vii) "subscription" shall have the meaning set forth in
3Section 1-10 of the Illinois Power Agency Act; and (viii)
4"energy storage system" means commercially available
5technology that is capable of absorbing energy and storing it
6for a period of time for use at a later time, including, but
7not limited to, electrochemical, thermal, and
8electromechanical technologies, and may be interconnected
9behind the customer's meter or interconnected behind its own
10meter.
11 (c) A net metering facility shall be equipped with
12metering equipment that can measure the flow of electricity in
13both directions at the same rate.
14 (1) For eligible customers whose electric service has
15 not been declared competitive pursuant to Section 16-113
16 of this Act as of July 1, 2011 and whose electric delivery
17 service is provided and measured on a kilowatt-hour basis
18 and electric supply service is not provided based on
19 hourly pricing, this shall typically be accomplished
20 through use of a single, bi-directional meter. If the
21 eligible customer's existing electric revenue meter does
22 not meet this requirement, the electricity provider shall
23 arrange for the local electric utility or a meter service
24 provider to install and maintain a new revenue meter at
25 the electricity provider's expense, which may be the smart
26 meter described by subsection (b) of Section 16-108.5 of

HB2640- 144 -LRB102 13765 SPS 19115 b
1 this Act.
2 (2) For eligible customers whose electric service has
3 not been declared competitive pursuant to Section 16-113
4 of this Act as of July 1, 2011 and whose electric delivery
5 service is provided and measured on a kilowatt demand
6 basis and electric supply service is not provided based on
7 hourly pricing, this shall typically be accomplished
8 through use of a dual channel meter capable of measuring
9 the flow of electricity both into and out of the
10 customer's facility at the same rate and ratio. If such
11 customer's existing electric revenue meter does not meet
12 this requirement, then the electricity provider shall
13 arrange for the local electric utility or a meter service
14 provider to install and maintain a new revenue meter at
15 the electricity provider's expense, which may be the smart
16 meter described by subsection (b) of Section 16-108.5 of
17 this Act.
18 (3) For all other eligible customers, until such time
19 as the local electric utility installs a smart meter, as
20 described by subsection (b) of Section 16-108.5 of this
21 Act, the electricity provider may arrange for the local
22 electric utility or a meter service provider to install
23 and maintain metering equipment capable of measuring the
24 flow of electricity both into and out of the customer's
25 facility at the same rate and ratio, typically through the
26 use of a dual channel meter. If the eligible customer's

HB2640- 145 -LRB102 13765 SPS 19115 b
1 existing electric revenue meter does not meet this
2 requirement, then the costs of installing such equipment
3 shall be paid for by the customer.
4 (d) An electricity provider shall measure and charge or
5credit for the net electricity supplied to eligible customers
6or provided by eligible customers whose electric service has
7not been declared competitive pursuant to Section 16-113 of
8this Act as of July 1, 2011 and whose electric delivery service
9is provided and measured on a kilowatt-hour basis and electric
10supply service is not provided based on hourly pricing in the
11following manner:
12 (1) If the amount of electricity used by the customer
13 during the billing period exceeds the amount of
14 electricity produced by the customer, the electricity
15 provider shall charge the customer for the net electricity
16 supplied to and used by the customer as provided in
17 subsection (e-5) of this Section.
18 (2) If the amount of electricity produced by a
19 customer during the billing period exceeds the amount of
20 electricity used by the customer during that billing
21 period, the electricity provider supplying that customer
22 shall apply a 1:1 kilowatt-hour credit to a subsequent
23 bill for service to the customer for the net electricity
24 supplied to the electricity provider. The electricity
25 provider shall continue to carry over any excess
26 kilowatt-hour credits earned and apply those credits to

HB2640- 146 -LRB102 13765 SPS 19115 b
1 subsequent billing periods to offset any
2 customer-generator consumption in those billing periods
3 until all credits are used or until the end of the
4 annualized period.
5 (3) At the end of the year or annualized over the
6 period that service is supplied by means of net metering,
7 or in the event that the retail customer terminates
8 service with the electricity provider prior to the end of
9 the year or the annualized period, any remaining credits
10 in the customer's account shall expire.
11 (d-5) An electricity provider shall measure and charge or
12credit for the net electricity supplied to eligible customers
13or provided by eligible customers whose electric service has
14not been declared competitive pursuant to Section 16-113 of
15this Act as of July 1, 2011 and whose electric delivery service
16is provided and measured on a kilowatt-hour basis and electric
17supply service is provided based on hourly pricing or
18time-of-use rates in the following manner:
19 (1) If the amount of electricity used by the customer
20 during any hourly period exceeds the amount of electricity
21 produced by the customer, the electricity provider shall
22 charge the customer for the net electricity supplied to
23 and used by the customer according to the terms of the
24 contract or tariff to which the same customer would be
25 assigned to or be eligible for if the customer was not a
26 net metering customer.

HB2640- 147 -LRB102 13765 SPS 19115 b
1 (2) If the amount of electricity produced by a
2 customer during any hourly period or time-of-use period
3 exceeds the amount of electricity used by the customer
4 during that hourly period or time-of-use period, the
5 energy provider shall apply a credit for the net
6 kilowatt-hours produced in such period. The credit shall
7 consist of an energy credit and a delivery service credit.
8 The energy credit shall be valued at the same price per
9 kilowatt-hour as the electric service provider would
10 charge for kilowatt-hour energy sales during that same
11 hourly or time-of-use period. The delivery credit shall be
12 equal to the net kilowatt-hours produced in such hourly or
13 time-of-use period times a credit that reflects all
14 kilowatt-hour based charges in the customer's electric
15 service rate, excluding energy charges.
16 (e) An electricity provider shall measure and charge or
17credit for the net electricity supplied to eligible customers
18whose electric service has not been declared competitive
19pursuant to Section 16-113 of this Act as of July 1, 2011 and
20whose electric delivery service is provided and measured on a
21kilowatt demand basis and electric supply service is not
22provided based on hourly pricing in the following manner:
23 (1) If the amount of electricity used by the customer
24 during the billing period exceeds the amount of
25 electricity produced by the customer, then the electricity
26 provider shall charge the customer for the net electricity

HB2640- 148 -LRB102 13765 SPS 19115 b
1 supplied to and used by the customer as provided in
2 subsection (e-5) of this Section. The customer shall
3 remain responsible for all taxes, fees, and utility
4 delivery charges that would otherwise be applicable to the
5 net amount of electricity used by the customer.
6 (2) If the amount of electricity produced by a
7 customer during the billing period exceeds the amount of
8 electricity used by the customer during that billing
9 period, then the electricity provider supplying that
10 customer shall apply a 1:1 kilowatt-hour credit that
11 reflects the kilowatt-hour based charges in the customer's
12 electric service rate to a subsequent bill for service to
13 the customer for the net electricity supplied to the
14 electricity provider. The electricity provider shall
15 continue to carry over any excess kilowatt-hour credits
16 earned and apply those credits to subsequent billing
17 periods to offset any customer-generator consumption in
18 those billing periods until all credits are used or until
19 the end of the annualized period.
20 (3) At the end of the year or annualized over the
21 period that service is supplied by means of net metering,
22 or in the event that the retail customer terminates
23 service with the electricity provider prior to the end of
24 the year or the annualized period, any remaining credits
25 in the customer's account shall expire.
26 (e-5) An electricity provider shall provide electric

HB2640- 149 -LRB102 13765 SPS 19115 b
1service to eligible customers who utilize net metering at
2non-discriminatory rates that are identical, with respect to
3rate structure, retail rate components, and any monthly
4charges, to the rates that the customer would be charged if not
5a net metering customer. An electricity provider shall not
6charge net metering customers any fee or charge or require
7additional equipment, insurance, or any other requirements not
8specifically authorized by interconnection standards
9authorized by the Commission, unless the fee, charge, or other
10requirement would apply to other similarly situated customers
11who are not net metering customers. The customer will remain
12responsible for all taxes, fees, and utility delivery charges
13that would otherwise be applicable to the net amount of
14electricity used by the customer. Subsections (c) through (e)
15of this Section shall not be construed to prevent an
16arms-length agreement between an electricity provider and an
17eligible customer that sets forth different prices, terms, and
18conditions for the provision of net metering service,
19including, but not limited to, the provision of the
20appropriate metering equipment for non-residential customers.
21 (f) Notwithstanding the requirements of subsections (c)
22through (e-5) of this Section, an electricity provider must
23require dual-channel metering for customers operating eligible
24renewable electrical generating facilities with a nameplate
25rating up to 2,000 kilowatts and to whom the provisions of
26neither subsection (d), (d-5), nor (e) of this Section apply.

HB2640- 150 -LRB102 13765 SPS 19115 b
1In such cases, electricity charges and credits shall be
2determined as follows:
3 (1) The electricity provider shall assess and the
4 customer remains responsible for all taxes, fees, and
5 utility delivery charges that would otherwise be
6 applicable to the gross amount of kilowatt-hours supplied
7 to the eligible customer by the electricity provider.
8 (2) Each month that service is supplied by means of
9 dual-channel metering, the electricity provider shall
10 compensate the eligible customer for any excess
11 kilowatt-hour credits at the electricity provider's
12 avoided cost of electricity supply over the monthly period
13 or as otherwise specified by the terms of a power-purchase
14 agreement negotiated between the customer and electricity
15 provider.
16 (3) For all eligible net metering customers taking
17 service from an electricity provider under contracts or
18 tariffs employing hourly or time of use rates, any monthly
19 consumption of electricity shall be calculated according
20 to the terms of the contract or tariff to which the same
21 customer would be assigned to or be eligible for if the
22 customer was not a net metering customer. When those same
23 customer-generators are net generators during any discrete
24 hourly or time of use period, the net kilowatt-hours
25 produced shall be valued at the same price per
26 kilowatt-hour as the electric service provider would

HB2640- 151 -LRB102 13765 SPS 19115 b
1 charge for retail kilowatt-hour sales during that same
2 time of use period.
3 (g) For purposes of federal and State laws providing
4renewable energy credits or greenhouse gas credits, the
5eligible customer shall be treated as owning and having title
6to the renewable energy attributes, renewable energy credits,
7and greenhouse gas emission credits related to any electricity
8produced by the qualified generating unit. The electricity
9provider may not condition participation in a net metering
10program on the signing over of a customer's renewable energy
11credits; provided, however, this subsection (g) shall not be
12construed to prevent an arms-length agreement between an
13electricity provider and an eligible customer that sets forth
14the ownership or title of the credits.
15 (h) Within 120 days after the effective date of this
16amendatory Act of the 95th General Assembly, the Commission
17shall establish standards for net metering and, if the
18Commission has not already acted on its own initiative,
19standards for the interconnection of eligible renewable
20generating equipment to the utility system. The
21interconnection standards shall address any procedural
22barriers, delays, and administrative costs associated with the
23interconnection of customer-generation while ensuring the
24safety and reliability of the units and the electric utility
25system. The Commission shall consider the Institute of
26Electrical and Electronics Engineers (IEEE) Standard 1547 and

HB2640- 152 -LRB102 13765 SPS 19115 b
1the issues of (i) reasonable and fair fees and costs, (ii)
2clear timelines for major milestones in the interconnection
3process, (iii) nondiscriminatory terms of agreement, and (iv)
4any best practices for interconnection of distributed
5generation.
6 Within 90 days after the effective date of this amendatory
7Act of the 102nd General Assembly, the Commission shall open a
8proceeding to update the interconnection standards and
9applicable utility tariffs. For the public interest, safety,
10and welfare of Illinois citizens, the Commission may adopt
11emergency rules under Section 5-45 of the Illinois
12Administrative Procedure Act to implement this Section. In
13addition to items (i) through (iv) in this subsection (h), the
14Commission shall also revise the standards to address the
15following, including, but not limited to, critical standards
16for interconnection:
17 (i) transparency and accuracy of costs, both direct
18 and indirect, while maintaining system security through
19 the effective management of confidentiality agreements;
20 (ii) standardization of typical costs associated with
21 interconnection;
22 (iii) transparency of the interconnection queue or
23 queues and hosting capacity;
24 (iv) development of hosting capacity maps that enable
25 greater visibility to customers about the locations with
26 the greatest need or availability;

HB2640- 153 -LRB102 13765 SPS 19115 b
1 (v) predictability of the queue management process and
2 enforcement of timelines;
3 (vi) benefits and challenges associated with group
4 studies and cost sharing;
5 (vii) minimum requirements for application to the
6 interconnection process and throughout the interconnection
7 process to avoid queue clogging behavior;
8 (viii) requiring that the electric utility performing
9 the interconnection study justify their interconnection
10 study cost and the estimates of costs for identified
11 upgrades, and to cap payments required by the
12 interconnection customer for the electric utility
13 installed facilities to the lesser of +50% of the
14 Feasibility Study estimate, +25% of the System Impact
15 Study estimate, or +10% of the Facilities Study estimate;
16 (ix) allowing customers to self-supply interconnection
17 studies when the electric utility are unable provide such
18 studies at a reasonable cost and schedule;
19 (x) allowing customers to self-build system upgrades
20 consistent with electric utility standards when the
21 electric utility cannot provide such upgrades and
22 interconnection facilities at a reasonable cost and
23 schedule;
24 (xi) preventing the electric utility from adding
25 overheads to their actual and estimated costs for both
26 studies and system upgrades. Provide a mechanism for a

HB2640- 154 -LRB102 13765 SPS 19115 b
1 customer to review invoices and internal accounting
2 statements to verify costs incurred by the electric
3 utility;
4 (xii) requiring all interconnection agreements to be
5 filed with the Illinois Commerce Commission;
6 (xiii) revising the electric utility reporting
7 requirements to include information regarding ability of
8 utilities to meet timelines established under these
9 interconnection standards and to introduce penalties for
10 utilities that do not meet such requirements, to be
11 commensurate with penalties faced by interconnection
12 customers that fail to meet requirements under these
13 interconnection standards;
14 (xiv) facilitating the deployment of energy storage
15 systems while ensuring the continued grid safety and
16 reliability of the system, including addressing the
17 following:
18 (1) treatment of energy storage systems as
19 generation for purposes of the interconnection,
20 ownership and operation;
21 (2) fair study assumptions that reflect the
22 operational profile of the energy storage device;
23 (3) streamlined notification-only interconnection
24 requirements for non-exporting systems that meet
25 utility criteria for safety and reliability, as is
26 determined through a robust stakeholder process; and

HB2640- 155 -LRB102 13765 SPS 19115 b
1 (4) enabling exports from customer-sited energy
2 storage systems for participation either in utility
3 programs or wholesale markets; and
4 (xv) establishment of a dispute resolution process
5 designed to address instances of unreasonable impediments
6 by an electric utility to the critical standards for
7 interconnection enumerated in subsections (i) through
8 (xiv) of this subsection (h). The Commission will make
9 available adequate Commission Staff for this dispute
10 resolution process to ensure that matters are decided on
11 an expedited basis.
12 As part of this proceeding, the Commission shall establish
13an interconnection working group. The working group shall
14include representatives from electric utilities, developers of
15renewable electric generating facilities, other industries
16that regularly apply for interconnection with the electric
17utilities, representatives of distributed generation
18customers, the Commission staff, and other stakeholders with a
19substantial interest in the topics addressed by the working
20group. The working group shall address cost and best available
21technology for interconnection and metering, distribution
22system upgrade cost avoidance through use of advanced inverter
23functions, process and customer service for interconnecting
24customers adopting distributed energy resources, including
25energy storage; options for metering distributed energy
26resources, including energy storage; interconnection of new

HB2640- 156 -LRB102 13765 SPS 19115 b
1technologies, including smart inverters and energy storage,
2and, without limitation, other technical, policy, and tariff
3issues related to and affecting interconnection performance
4and customer service, as determined by the working group. The
5Commission may create working group subcommittees of the
6working group to focus on specific issues of importance, as
7appropriate. The working group shall report to the Commission
8on recommended improvements to interconnection rules and
9tariffs and such other recommendations as determined by the
10working group, within 6 months of its first meeting, and every
116 months thereafter. Such report shall include consensus
12recommendations of the working group and, if applicable,
13additional recommendations for which consensus was not
14reached. The outcomes of the working group shall inform the
15policies, processes, tariffs, and standards associated with
16interconnection and should create standards and processes that
17support the achievement of the objectives in subparagraph (K)
18of paragraph (1) of subsection (c) of Section 1-75 of the
19Illinois Power Agency Act.
20 (i) All electricity providers shall begin to offer net
21metering no later than April 1, 2008.
22 (j) An electricity utility provider shall provide net
23metering to eligible customers until the load of its net
24metering customers equals 5% of the total peak demand
25delivered supplied by that electricity provider during the
26previous year. After such time as the load of the electricity

HB2640- 157 -LRB102 13765 SPS 19115 b
1provider's net metering customers equals 5% of the total peak
2demand delivered supplied by that electricity utility provider
3during the previous year, and the Commission has approved the
4distributed generation rebate and applicable tariff following
5investigation as set out in subsection (e) of Section 16-107.6
6of this Act, eligible customers that begin taking net metering
7shall only be eligible for netting of energy.
8 (k) Each electricity provider shall maintain records and
9report annually to the Commission the total number of net
10metering customers served by the provider, as well as the
11type, capacity, and energy sources of the generating systems
12used by the net metering customers. Nothing in this Section
13shall limit the ability of an electricity provider to request
14the redaction of information deemed by the Commission to be
15confidential business information.
16 (l)(1) Notwithstanding the definition of "eligible
17customer" in item (ii) of subsection (b) of this Section, each
18electricity provider shall allow net metering as set forth in
19this subsection (l) and for the following projects, provided
20that only electric utilities shall provide net metering for
21subparagraph (C) of this paragraph (1):
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

HB2640- 158 -LRB102 13765 SPS 19115 b
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.
13 In addition, the nameplate capacity of the eligible
14renewable electric generating facility that serves the demand
15of the properties, units, or apartments identified in
16paragraphs (1) and (2) of this subsection (l) shall not exceed
172,000 kilowatts in nameplate capacity in total. Any eligible
18renewable electrical generating facility or community
19renewable generation project that is powered by photovoltaic
20electric energy and installed after the effective date of this
21amendatory Act of the 99th General Assembly must be installed
22by a qualified person in compliance with the requirements of
23Section 16-128A of the Public Utilities Act and any rules or
24regulations adopted thereunder.
25 (2) Notwithstanding anything to the contrary and
26regardless of whether a subscriber receives power and energy

HB2640- 159 -LRB102 13765 SPS 19115 b
1service from the electric utility or an alternative retail
2electric supplier, the electric utility , an electricity
3provider shall provide credits for the electricity produced by
4the community renewable generation projects projects described
5in paragraph (1) of this subsection (l). The electric utility
6electricity provider shall provide credits at the utility's
7total price to compare subscriber's energy supply rate 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 the purposes of
11this subsection, "total price to compare" means the rate or
12rates published by the Illinois Commerce Commission for energy
13supply for eligible customers receiving supply service from
14the electric utility, and shall include energy, capacity,
15transmission, and the purchased energy adjustment. The credit
16provided by the electric utility shall be adjusted monthly to
17reflect the total price to compare of the applicable month but
18may never result in a credit equal to less than the total price
19to compare as of January 1, 2021. Any applicable credit or
20reduction in load obligation from the production of the
21community renewable generating projects receiving a credit
22under this subsection shall be credited to the electric
23utility to offset the cost of providing the credit. To the
24extent that the credit or load obligation reduction does not
25completely offset the cost of providing the credit to
26subscribers of community renewable generation projects as

HB2640- 160 -LRB102 13765 SPS 19115 b
1described in this subsection the electric utility may recover
2the remaining costs through the process established in Section
316-111.8 of this Act.
4 (3) 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 hours 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

HB2640- 161 -LRB102 13765 SPS 19115 b
1 Assembly this amendatory Act of the 99th General Assembly.
2 The owner or operator shall separately provide the
3 electric utility with the documentation detailing the
4 calculations supporting the credit in the manner set forth
5 in the applicable tariff.
6 (B) For those participating customers in projects
7 described in subparagraph (A) of this paragraph (3) and
8 subscribers who receive their energy supply from an
9 alternative retail electric supplier, the electric utility
10 shall remit to the applicable alternative retail electric
11 supplier the information provided under subparagraph (A)
12 of this paragraph (3) for such customers and subscribers
13 in a manner set forth in such alternative retail electric
14 supplier's net metering program, or as otherwise agreed
15 between the utility and the alternative retail electric
16 supplier. The alternative retail electric supplier shall
17 then submit to the utility the amount of the charges for
18 power and energy to be applied to such customers and
19 subscribers, including the amount of the credit associated
20 with net metering.
21 (C) A participating customer or subscriber may provide
22 authorization as required by applicable law that directs
23 the electric utility to submit information to the owner or
24 operator of the eligible renewable electrical generating
25 facility or community renewable generation project to
26 which the customer or subscriber has an ownership or

HB2640- 162 -LRB102 13765 SPS 19115 b
1 leasehold interest or a subscription. Such information
2 shall be limited to the components of the net metering
3 credit calculated under this subsection (l), including the
4 bill credit rate, total kilowatthours, and total monetary
5 credit value applied to the customer's or subscriber's
6 bill for the monthly billing period.
7 (l-5) Within 90 days after the effective date of this
8amendatory Act of the 102nd General Assembly this amendatory
9Act of the 99th General Assembly, each electric utility
10subject to this Section shall file a tariff to implement the
11provisions of subsection (l) of this Section, which shall,
12consistent with the provisions of subsection (l), describe the
13terms and conditions under which owners or operators of
14qualifying properties, units, or apartments may participate in
15net metering. The Commission shall approve, or approve with
16modification, the tariff within 120 days after the effective
17date of this amendatory Act of the 102nd General Assembly this
18amendatory Act of the 99th General Assembly.
19 (m) Nothing in this Section shall affect the right of an
20electricity provider to continue to provide, or the right of a
21retail customer to continue to receive service pursuant to a
22contract for electric service between the electricity provider
23and the retail customer in accordance with the prices, terms,
24and conditions provided for in that contract. Either the
25electricity provider or the customer may require compliance
26with the prices, terms, and conditions of the contract.

HB2640- 163 -LRB102 13765 SPS 19115 b
1 (n) At such time, if any, that the load of the electricity
2utility's provider's net metering customers equals 5% of the
3total peak demand delivered supplied by that electricity
4utility provider during the previous year, as specified in
5subsection (j) of this Section, and the Commission has
6approved the distributed generation rebate and applicable
7tariff following investigation set out in subsection (e) of
8Section 16-107.6 of this Act, the net metering services
9described in subsections (d), (d-5), (e), (e-5), and (f) of
10this Section shall no longer be offered, except as to those
11retail customers that are receiving net metering service under
12these subsections at the time the net metering services under
13those subsections are no longer offered, who shall continue to
14receive net metering services described in subsections (d),
15(d-5), (e), (e-5), and (f) of this Section for the lifetime of
16the system, regardless of whether those retail customers
17change electricity providers. Those retail customers that
18begin taking net metering service after the date that net
19metering services are no longer offered under such subsections
20shall be subject to the provisions set forth in the following
21paragraphs (1) through (3) of this subsection (n):
22 (1) An electricity provider shall charge or credit for
23 the net electricity supplied to eligible customers or
24 provided by eligible customers whose electric supply
25 service is not provided based on hourly pricing in the
26 following manner:

HB2640- 164 -LRB102 13765 SPS 19115 b
1 (A) If the amount of electricity used by the
2 customer during the billing period exceeds the amount
3 of electricity produced by the customer, then the
4 electricity provider shall charge the customer for the
5 net kilowatt-hour based electricity charges reflected
6 in the customer's electric service rate supplied to
7 and used by the customer as provided in paragraph (3)
8 of this subsection (n).
9 (B) If the amount of electricity produced by a
10 customer during the billing period exceeds the amount
11 of electricity used by the customer during that
12 billing period, then the electricity provider
13 supplying that customer shall apply a 1:1
14 kilowatt-hour energy credit that reflects the
15 kilowatt-hour based energy charges in the customer's
16 electric service rate to a subsequent bill for service
17 to the customer for the net electricity supplied to
18 the electricity provider. The electricity provider
19 shall continue to carry over any excess kilowatt-hour
20 energy credits earned and apply those credits to
21 subsequent billing periods to offset any
22 customer-generator consumption in those billing
23 periods until all credits are used or until the end of
24 the annualized period.
25 (C) At the end of the year or annualized over the
26 period that service is supplied by means of net

HB2640- 165 -LRB102 13765 SPS 19115 b
1 metering, or in the event that the retail customer
2 terminates service with the electricity provider prior
3 to the end of the year or the annualized period, any
4 remaining credits in the customer's account shall
5 expire.
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. The value of the energy credit shall be
23 calculated using the same price per kilowatt-hour as
24 the electric service provider would charge for
25 kilowatt-hour energy sales during that same hourly
26 period.

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1 (3) An electricity provider shall provide electric
2 service to eligible customers who utilize net metering at
3 non-discriminatory rates that are identical, with respect
4 to rate structure, retail rate components, and any monthly
5 charges, to the rates that the customer would be charged
6 if not a net metering customer. An electricity provider
7 shall charge the customer for the net electricity supplied
8 to and used by the customer according to the terms of the
9 contract or tariff to which the same customer would be
10 assigned or be eligible for if the customer was not a net
11 metering customer. An electricity provider shall not
12 charge net metering customers any fee or charge or require
13 additional equipment, insurance, or any other requirements
14 not specifically authorized by interconnection standards
15 authorized by the Commission, unless the fee, charge, or
16 other requirement would apply to other similarly situated
17 customers who are not net metering customers. The charge
18 or credit that the customer receives for net electricity
19 shall be at a rate equal to the customer's energy supply
20 rate. The customer remains responsible for the gross
21 amount of delivery services charges, supply-related
22 charges that are kilowatt based, and all taxes and fees
23 related to such charges. The customer also remains
24 responsible for all taxes and fees that would otherwise be
25 applicable to the net amount of electricity used by the
26 customer. Paragraphs (1) and (2) of this subsection (n)

HB2640- 167 -LRB102 13765 SPS 19115 b
1 shall not be construed to prevent an arms-length agreement
2 between an electricity provider and an eligible customer
3 that sets forth different prices, terms, and conditions
4 for the provision of net metering service, including, but
5 not limited to, the provision of the appropriate metering
6 equipment for non-residential customers. Nothing in this
7 paragraph (3) shall be interpreted to mandate that a
8 utility that is only required to provide delivery services
9 to a given customer must also sell electricity to such
10 customer.
11 (o) Within 90 days after the effective date of this
12amendatory Act of the 102nd General Assembly, each electric
13utility subject to this Section shall file a tariff that
14shall, consistent with the provisions this Section, propose
15the terms and conditions under which an eligible customer may
16participate in net metering. The Commission shall approve, or
17approve with modification based on stakeholder process, the
18tariff within 120 days after effective date of this amendatory
19Act of the 102nd General Assembly. Each electric utility shall
20file any changes to terms as a subsequent tariff for approval
21or approval with modifications from Commission.
22(Source: P.A. 99-906, eff. 6-1-17.)
23 (220 ILCS 5/16-107.6)
24 Sec. 16-107.6. Distributed generation rebate.
25 (a) In this Section:

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1 "Energy storage system" means commercially available
2technology that is capable of absorbing energy and storing it
3for a period of time for use at a later time, including, but
4not limited to, electrochemical, thermal, and
5electromechanical technologies, and may be interconnected
6behind the customer's meter or interconnected behind its own
7meter.
8 "Smart inverter" means a device that converts direct
9current into alternating current and can autonomously
10contribute to grid support during excursions from normal
11operating voltage and frequency conditions by providing each
12of the following: dynamic reactive and real power support,
13voltage and frequency ride-through, ramp rate controls,
14communication systems with ability to accept external
15commands, and other functions from the electric utility as
16approved by the Illinois Commerce Commission.
17 "Subscriber" has the meaning set forth in Section 1-10 of
18the Illinois Power Agency Act.
19 "Subscription" has the meaning set forth in Section 1-10
20of the Illinois Power Agency Act.
21 "Threshold date" means the date on which the load of an
22electricity utility's provider's net metering customers equals
235% of the total peak demand delivered supplied by that
24electricity utility provider during the previous year, as
25specified under subsection (j) of Section 16-107.5 of this
26Act.

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1 (b) An electric utility that serves more than 200,000
2customers in the State shall file a petition with the
3Commission requesting approval of the utility's tariff to
4provide a rebate to a retail customer who owns, hosts, or
5operates distributed generation, including third-party-owned
6systems, that meets the following criteria:
7 (1) has a nameplate generating capacity no greater
8 than 2,000 kilowatts and is primarily used to offset that
9 customer's electricity load;
10 (2) is located on the customer's premises, for the
11 customer's own use, and not for commercial use or sales,
12 including, but not limited to, wholesale sales of electric
13 power and energy;
14 (3) is located in the electric utility's service
15 territory; and
16 (4) is interconnected under rules adopted by the
17 Commission by means of the inverter or smart inverter
18 required by this Section, as applicable.
19 For purposes of this Section, "distributed generation"
20shall satisfy the definition of distributed renewable energy
21generation device set forth in Section 1-10 of the Illinois
22Power Agency Act to the extent such definition is consistent
23with the requirements of this Section.
24 In addition, any new photovoltaic distributed generation
25that is installed after the effective date of this amendatory
26Act of the 99th General Assembly must be installed by a

HB2640- 170 -LRB102 13765 SPS 19115 b
1qualified person, as defined by subsection (i) of Section 1-56
2of the Illinois Power Agency Act.
3 The tariff shall provide that the utility shall be
4permitted to operate and control the smart inverter associated
5with the distributed generation that is the subject of the
6rebate for the purpose of preserving reliability during
7distribution system reliability events and shall address the
8terms and conditions of the operation and the compensation
9associated with the operation. Nothing in this Section shall
10negate or supersede Institute of Electrical and Electronics
11Engineers interconnection requirements or standards or other
12similar standards or requirements. The tariff shall also
13provide for additional uses of the smart inverter that shall
14be optional for the owner of the distributed generation owner
15to activate and, if activated, shall be separately compensated
16so as to mitigate loss of revenue to the owner of the
17distributed generation for production curtailment or
18diminishment of real power output due to the activation of
19such uses. Such additional uses shall and which may include,
20but are not limited to, voltage and VAR support, voltage watt,
21frequency watt, regulation, and other grid services. As part
22of the proceeding described in subsection (e) of this Section,
23the Commission shall review and determine whether smart
24inverters can provide any additional uses or services. If the
25Commission determines that an additional use or service would
26be beneficial, the Commission shall determine the terms and

HB2640- 171 -LRB102 13765 SPS 19115 b
1conditions of the operation and shall approve compensation for
2activation of additional uses in a monetary form. The
3Commission shall also approve the ability of the utility to
4offer compensation to the owner of the distributed generation
5owner in the form of reduced project-specific interconnection
6upgrades, and the owner of the distributed generation may
7choose either the monetary compensation or the reduction in
8interconnection upgrades and how the use or service should be
9separately compensated.
10 (c) The proposed tariff authorized by subsection (b) of
11this Section shall include the following participation terms
12and formulae to calculate the value of the rebates to be
13applied under this Section for distributed generation that
14satisfies the criteria set forth in subsection (b) of this
15Section:
16 (1) Until the utility files its tariff or tariffs to
17 place into effect the rebate values established by the
18 Commission under subsection (e) of this Section,
19 non-residential customers that are taking service under a
20 net metering program offered by an electricity provider
21 under the terms of Section 16-107.5 of this Act may apply
22 for a rebate as provided for in this Section. The value of
23 the rebate shall be $250 per kilowatt of nameplate
24 generating capacity, measured as nominal DC power output,
25 of a non-residential customer's distributed generation. To
26 the extent the distributed generation system also has a

HB2640- 172 -LRB102 13765 SPS 19115 b
1 storage device as part of the system, and said storage
2 uses the same smart inverter as the distributed
3 generation, then the storage shall be separately
4 compensated at $350 per kilowatt of nameplate capacity.
5 Energy storage nameplate capacity means the kilowatt-hour
6 of rated AC capacity of the installed system.
7 (2) After the utility's tariff or tariffs setting the
8 new rebate values established under subsection (d) of this
9 Section take effect, retail customers may, as applicable,
10 make the following elections:
11 (A) Residential customers that are taking service
12 under a net metering program offered by an electricity
13 provider under the terms of Section 16-107.5 of this
14 Act on the threshold date may elect to either continue
15 to take such service under the terms of such program as
16 in effect on such threshold date for the useful life of
17 the customer's eligible renewable electric generating
18 facility as defined in such Section, or file an
19 application to receive a rebate under the terms of
20 this Section, provided that such application must be
21 submitted within 6 months after the effective date of
22 the tariff approved under subsection (d) of this
23 Section. The value of the rebate shall be the amount
24 established by the Commission and reflected in the
25 utility's tariff pursuant to subsection (e) of this
26 Section. If, on the threshold date, the proceeding

HB2640- 173 -LRB102 13765 SPS 19115 b
1 outlined in subsection (e) of this Section has not
2 concluded, the utility shall continue to offer
3 residential customers to maintain net metering as
4 outlined in Section 16-107.5 until the proceeding
5 under subsection (e) of this Section has concluded and
6 the tariff approved as a result of that proceeding is
7 available.
8 (B) Non-residential customers that are taking
9 service under a net metering program offered by an
10 electricity provider under the terms of Section
11 16-107.5 of this Act on the threshold date may apply
12 for a rebate as provided for in this Section. The value
13 of the rebate shall be the amount established by the
14 Commission and reflected in the utility's tariff
15 pursuant to subsection (e) of this Section.
16 (3) Upon approval of a rebate application submitted
17 under this subsection (c), the retail customer shall no
18 longer be entitled to receive any delivery service credits
19 for the excess electricity generated by its facility and
20 shall be subject to the provisions of subsection (n) of
21 Section 16-107.5 of this Act.
22 (4) To be eligible for a rebate described in this
23 subsection (c), customers who begin taking service after
24 the effective date of this amendatory Act of the 99th
25 General Assembly under a net metering program offered by
26 an electricity provider under the terms of Section

HB2640- 174 -LRB102 13765 SPS 19115 b
1 16-107.5 of this Act must have a smart inverter associated
2 with the customer's distributed generation.
3 (d) The Commission shall review the proposed tariff
4submitted under subsections (b) and (c) of this Section and
5may make changes to the tariff that are consistent with this
6Section and with the Commission's authority under Article IX
7of this Act, subject to notice and hearing. Following notice
8and hearing, the Commission shall issue an order approving, or
9approving with modification, such tariff no later than 240
10days after the utility files its tariff.
11 (e) When the total generating capacity of the electricity
12utility's provider's net metering customers is equal to 3% of
13the total peak demand delivered by that utility, the
14Commission shall open an investigation into a an annual
15process and formula for calculating the value of rebates for
16the retail customers described in subsections (b) and (f) of
17this Section that submit rebate applications after the
18threshold date for an electric utility that elected to file a
19tariff pursuant to this Section. The process and formula for
20calculating the value of the rebate available after the
21threshold date shall be updated every 5 years, and shall
22promote continuity in the distributed generation market. The
23investigation shall include diverse sets of stakeholders,
24calculations for valuing distributed energy resource benefits
25to the grid based on best practices, and assessments of
26present and future technological capabilities of distributed

HB2640- 175 -LRB102 13765 SPS 19115 b
1energy resources. The value of such rebates shall reflect the
2value of the distributed generation to the distribution system
3at the location at which it is interconnected, taking into
4account the geographic, time-based, and performance-based
5benefits, as well as technological capabilities and present
6and future grid needs. No later than 10 days after the
7Commission enters its final order under this subsection (e),
8the utility shall file its tariff or tariffs in compliance
9with the order, and the Commission shall approve, or approve
10with modification, the tariff or tariffs within 45 days after
11the utility's filing. For those rebate applications filed
12after the threshold date but before the utility's tariff or
13tariffs filed pursuant to this subsection (e) take effect, the
14value of the rebate shall remain at the value established in
15subsection (c) of this Section until the tariff is approved.
16 (f) Notwithstanding any provision of this Act to the
17contrary, the owner, developer, or subscriber of a generation
18facility that is part of a net metering program provided under
19subsection (l) of Section 16-107.5 shall also be eligible to
20apply for the rebate described in this Section. A subscriber
21to the generation facility may apply for a rebate in the amount
22of the subscriber's subscription only if the owner, developer,
23or previous subscriber to the same panel or panels has not
24already submitted an application, and, regardless of whether
25the subscriber is a residential or non-residential customer,
26may be allowed the amount identified in paragraph (1) of

HB2640- 176 -LRB102 13765 SPS 19115 b
1subsection (c) or in subsection (e) of this Section applicable
2to such customer on the date that the application is
3submitted. An application for a rebate for a portion of a
4project described in this subsection (f) may be submitted at
5or after the time that a related request for net metering is
6made.
7 (g) The owner of the distributed generation may apply for
8the tariff approved under subsection (d) or (e) of this
9Section at the time of application for interconnection with
10the distribution utility and shall receive the value of the
11rebate available at that time. However, the utility shall
12issue the rebate no No later than 60 days after the project is
13energized utility receives an application for a rebate under
14its tariff approved under subsection (d) or (e) of this
15Section, the utility shall issue a rebate to the applicant
16under the terms of the tariff. In the event the application is
17incomplete or the utility is otherwise unable to calculate the
18payment based on the information provided by the owner, the
19utility shall issue the payment no later than 60 days after the
20application is complete or all requested information is
21received.
22 (h) An electric utility shall recover from its retail
23customers all of the costs of the rebates made under a tariff
24or tariffs placed into effect under this Section, including,
25but not limited to, the value of the rebates and all costs
26incurred by the utility to comply with and implement this

HB2640- 177 -LRB102 13765 SPS 19115 b
1Section, consistent with the following provisions:
2 (1) The utility shall defer the full amount of its
3 costs incurred under this Section as a regulatory asset.
4 The total costs deferred as a regulatory asset shall be
5 amortized over a 15-year period. The unamortized balance
6 shall be recognized as of December 31 for a given year. The
7 utility shall also earn a return on the total of the
8 unamortized balance of the regulatory assets, less any
9 deferred taxes related to the unamortized balance, at an
10 annual rate equal to the utility's weighted average cost
11 of capital that includes, based on a year-end capital
12 structure, the utility's actual cost of debt for the
13 applicable calendar year and a cost of equity, which shall
14 be calculated as the sum of (i) the average for the
15 applicable calendar year of the monthly average yields of
16 30-year U.S. Treasury bonds published by the Board of
17 Governors of the Federal Reserve System in its weekly H.15
18 Statistical Release or successor publication; and (ii) 580
19 basis points, including a revenue conversion factor
20 calculated to recover or refund all additional income
21 taxes that may be payable or receivable as a result of that
22 return.
23 When an electric utility creates a regulatory asset
24 under the provisions of this Section, the costs are
25 recovered over a period during which customers also
26 receive a benefit, which is in the public interest.

HB2640- 178 -LRB102 13765 SPS 19115 b
1 Accordingly, it is the intent of the General Assembly that
2 an electric utility that elects to create a regulatory
3 asset under the provisions of this Section shall recover
4 all of the associated costs, including, but not limited
5 to, its cost of capital as set forth in this Section. After
6 the Commission has approved the prudence and
7 reasonableness of the costs that comprise the regulatory
8 asset, the electric utility shall be permitted to recover
9 all such costs, and the value and recoverability through
10 rates of the associated regulatory asset shall not be
11 limited, altered, impaired, or reduced. To enable the
12 financing of the incremental capital expenditures,
13 including regulatory assets, for electric utilities that
14 serve less than 3,000,000 retail customers but more than
15 500,000 retail customers in the State, the utility's
16 actual year-end capital structure that includes a common
17 equity ratio, excluding goodwill, of up to and including
18 50% of the total capital structure shall be deemed
19 reasonable and used to set rates.
20 (2) The utility, at its election, may recover all of
21 the costs it incurs under this Section as part of a filing
22 for a general increase in rates under Article IX of this
23 Act, as part of an annual filing to update a
24 performance-based formula rate under subsection (d) of
25 Section 16-108.5 of this Act, or through an automatic
26 adjustment clause tariff, provided that nothing in this

HB2640- 179 -LRB102 13765 SPS 19115 b
1 paragraph (2) permits the double recovery of such costs
2 from customers. If the utility elects to recover the costs
3 it incurs under this Section through an automatic
4 adjustment clause tariff, the utility may file its
5 proposed tariff together with the tariff it files under
6 subsection (b) of this Section or at a later time. The
7 proposed tariff shall provide for an annual
8 reconciliation, less any deferred taxes related to the
9 reconciliation, with interest at an annual rate of return
10 equal to the utility's weighted average cost of capital as
11 calculated under paragraph (1) of this subsection (h),
12 including a revenue conversion factor calculated to
13 recover or refund all additional income taxes that may be
14 payable or receivable as a result of that return, of the
15 revenue requirement reflected in rates for each calendar
16 year, beginning with the calendar year in which the
17 utility files its automatic adjustment clause tariff under
18 this subsection (h), with what the revenue requirement
19 would have been had the actual cost information for the
20 applicable calendar year been available at the filing
21 date. The Commission shall review the proposed tariff and
22 may make changes to the tariff that are consistent with
23 this Section and with the Commission's authority under
24 Article IX of this Act, subject to notice and hearing.
25 Following notice and hearing, the Commission shall issue
26 an order approving, or approving with modification, such

HB2640- 180 -LRB102 13765 SPS 19115 b
1 tariff no later than 240 days after the utility files its
2 tariff.
3 (i) No later than 90 days after the Commission enters an
4order, or order on rehearing, whichever is later, approving an
5electric utility's proposed tariff under subsection (d) of
6this Section, the electric utility shall provide notice of the
7availability of rebates under this Section. Subsequent to the
8utility's notice, any entity that offers in the State, for
9sale or lease, distributed generation and estimates the dollar
10saving attributable to such distributed generation shall
11provide estimates based on both delivery service credits and
12the rebates available under this Section.
13(Source: P.A. 99-906, eff. 6-1-17.)
14 (220 ILCS 5/16-107.7 new)
15 Sec. 16-107.7. Energy Storage Program.
16 (a) Findings. The Illinois General Assembly hereby finds
17and declares that:
18 (1) Energy storage systems provide opportunities to:
19 (A) reduce costs to ratepayers by avoiding or
20 deferring the need for investment in new generation
21 and for upgrades to systems for the transmission and
22 distribution of energy;
23 (B) reduce the use of fossil fuels for meeting
24 demand during peak load periods when charged off-peak
25 with low-emitting generation;

HB2640- 181 -LRB102 13765 SPS 19115 b
1 (C) provide ancillary services;
2 (D) assist electric regulated electric companies
3 with integrating sources of renewable energy into the
4 grid for the transmission and distribution of
5 electricity, and with maintaining grid stability;
6 (E) support diversification of energy resources;
7 (F) enhance the resilience and reliability of the
8 electric grid; and
9 (G) reduce greenhouse gases and other air
10 pollutants resulting from power generation, thereby
11 minimizing public health impacts that result from
12 power generation.
13 (2) There are significant barriers to obtaining the
14 benefits of energy storage systems, including inadequate
15 valuation of energy storage.
16 (3) It is in the public interest to:
17 (A) develop a robust competitive market for
18 existing and new providers of energy storage systems
19 in order to leverage Illinois' position as a leader in
20 energy storage systems and to capture the potential
21 for economic development;
22 (B) investigate the costs and benefits of energy
23 storage systems in the State of Illinois and, if such
24 an investigation indicates that the benefits of energy
25 storage systems exceed the costs of such systems, to
26 implement targets and programs to achieve deployment

HB2640- 182 -LRB102 13765 SPS 19115 b
1 of energy storage systems; and
2 (C) modernize distributed generation programs and
3 interconnection standards to lower costs and
4 efficiently deploy energy storage systems in order to
5 increase economic development and job creation within
6 the state's emerging clean energy economy.
7 (b) Definitions. In this Section:
8 "Bring Your Own Device program" means a utility pilot
9program that enables customers to provide grid services to a
10utility in exchange for an on-bill credit, upfront payment, or
11other contractual agreement.
12 "Clean peak standard" means a percentage of annual retail
13electricity sales during peak hours that an electric utility
14must derive from eligible clean energy resources.
15 "Deployment" means the installation of energy storage
16systems through a variety of mechanisms, including utility
17procurement, customer installation, or other processes.
18 "Electric utility" has the same meaning as provided in
19Section 16-102 of the Public Utilities Act.
20 "Energy storage system" means commercially available
21technology that is capable of absorbing energy and storing it
22for a period of time for use at a later time including, but not
23limited to, electrochemical, thermal, and electromechanical
24technologies, and may be interconnected behind the customer's
25meter or interconnected behind its own meter.
26 "Non-wires alternatives solicitation" means a utility

HB2640- 183 -LRB102 13765 SPS 19115 b
1solicitation for third-party-owned or utility-owned
2distributed energy resource investment that uses
3nontraditional solutions to defer or replace planned
4investment on the distribution or transmission system.
5 (c) Cost-benefit assessment.
6 (1) The Commission, in consultation with the Illinois
7 Power Agency, shall study and produce a report analyzing
8 the potential for energy storage in Illinois, including
9 the costs and benefits of energy storage systems, as well
10 as barriers to the development of energy storage in
11 Illinois. The Illinois Commerce Commission shall engage a
12 broad group of Illinois stakeholders, including electric
13 utilities, the energy storage industry, the renewable
14 energy industry, and others to develop and provide
15 information for the report.
16 (2) The study must, at minimum:
17 (A) Identify and measure the potential costs and
18 benefits, along with barriers to realizing such
19 benefits, that the deployment of energy storage
20 systems can produce, including, but not limited to:
21 (i) avoided cost and deferred investments in
22 generation, transmission, and distribution
23 facilities;
24 (ii) reduced ancillary services costs;
25 (iii) reduced transmission and distribution
26 congestion;

HB2640- 184 -LRB102 13765 SPS 19115 b
1 (iv) lower peak power costs and reduce
2 capacity costs;
3 (v) reduced costs for emergency power supplies
4 during outages;
5 (vi) reduced curtailment of renewable energy
6 generators;
7 (vii) reduced greenhouse gas emissions and
8 other criteria air pollutants;
9 (viii) increased grid hosting capacity of
10 renewable energy generators that produce energy on
11 an intermittent basis;
12 (ix) increased reliability and resilience of
13 the electric grid;
14 (x) increased resource diversification;
15 (xi) increased economic development; and
16 (xii) electric utility costs associated with
17 the integration of energy storage on the grid.
18 (B) Analyze and estimate:
19 (i) the impact on the system's ability to
20 integrate renewable resources;
21 (ii) the benefits of addition of storage at
22 existing peaking units;
23 (iii) the impact on grid reliability and power
24 quality; and
25 (iv) the effect on retail electric rates over
26 the useful life of a given energy storage system

HB2640- 185 -LRB102 13765 SPS 19115 b
1 compared to providing the same services using
2 other facilities or resources.
3 (C) Evaluate and identify cost-effective policies
4 and programs to support the deployment of energy
5 storage systems, including, but not limited to:
6 (i) rebate programs;
7 (ii) clean peak standards;
8 (iii) non-wires alternative solicitation;
9 (iv) bring Your Own Device Program;
10 (v) contracted demand-response programs,
11 similar to the California Demand Response Auction
12 Mechanisms (DRAM);
13 (vi) tax incentives; and
14 (vii) procurement by the Illinois Power Agency
15 of energy storage resources.
16 (D) Make a recommendation on appropriate energy
17 storage deployment targets, including, but not limited
18 to:
19 (i) achieving a minimum of 1,000 MW of energy
20 storage systems by 2030 and more as identified in
21 the outcome of the energy storage systems
22 cost-benefit study required under subparagraph (C)
23 of paragraph (2) of this subsection (c);
24 (ii) adopting specific sub-categories of
25 deployment of systems by point of interconnection,
26 including customer-connected,

HB2640- 186 -LRB102 13765 SPS 19115 b
1 distribution-connected, and
2 transmission-connected;
3 (iii) adopting requirements or processes by
4 the Illinois Power Agency for competitive
5 deployment of energy storage services from third
6 parties; and
7 (iv) appropriate accountability mechanisms.
8 (3) By December 31, 2021, the findings and
9 recommendations for the programs, policies, and funding
10 levels to meet the energy storage deployment targets from
11 this study shall be submitted to the General Assembly and
12 the Governor for consideration and appropriate action.
13 The Illinois Power Agency shall include a plan to procure
14energy from energy storage resources pursuant to the results
15of this study as part of its Procurement Plan for 2023. An
16electric utility shall file tariffs directed by the Commission
17to recover from its retail customers the costs associated with
18the procurement of energy storage under this Section.
19 (220 ILCS 5/16-108)
20 Sec. 16-108. Recovery of costs associated with the
21provision of delivery and other services.
22 (a) An electric utility shall file a delivery services
23tariff with the Commission at least 210 days prior to the date
24that it is required to begin offering such services pursuant
25to this Act. An electric utility shall provide the components

HB2640- 187 -LRB102 13765 SPS 19115 b
1of delivery services that are subject to the jurisdiction of
2the Federal Energy Regulatory Commission at the same prices,
3terms and conditions set forth in its applicable tariff as
4approved or allowed into effect by that Commission. The
5Commission shall otherwise have the authority pursuant to
6Article IX to review, approve, and modify the prices, terms
7and conditions of those components of delivery services not
8subject to the jurisdiction of the Federal Energy Regulatory
9Commission, including the authority to determine the extent to
10which such delivery services should be offered on an unbundled
11basis. In making any such determination the Commission shall
12consider, at a minimum, the effect of additional unbundling on
13(i) the objective of just and reasonable rates, (ii) electric
14utility employees, and (iii) the development of competitive
15markets for electric energy services in Illinois.
16 (b) The Commission shall enter an order approving, or
17approving as modified, the delivery services tariff no later
18than 30 days prior to the date on which the electric utility
19must commence offering such services. The Commission may
20subsequently modify such tariff pursuant to this Act.
21 (c) The electric utility's tariffs shall define the
22classes of its customers for purposes of delivery services
23charges. Delivery services shall be priced and made available
24to all retail customers electing delivery services in each
25such class on a nondiscriminatory basis regardless of whether
26the retail customer chooses the electric utility, an affiliate

HB2640- 188 -LRB102 13765 SPS 19115 b
1of the electric utility, or another entity as its supplier of
2electric power and energy. Charges for delivery services shall
3be cost based, and shall allow the electric utility to recover
4the costs of providing delivery services through its charges
5to its delivery service customers that use the facilities and
6services associated with such costs. Such costs shall include
7the costs of owning, operating and maintaining transmission
8and distribution facilities. The Commission shall also be
9authorized to consider whether, and if so to what extent, the
10following costs are appropriately included in the electric
11utility's delivery services rates: (i) the costs of that
12portion of generation facilities used for the production and
13absorption of reactive power in order that retail customers
14located in the electric utility's service area can receive
15electric power and energy from suppliers other than the
16electric utility, and (ii) the costs associated with the use
17and redispatch of generation facilities to mitigate
18constraints on the transmission or distribution system in
19order that retail customers located in the electric utility's
20service area can receive electric power and energy from
21suppliers other than the electric utility. Nothing in this
22subsection shall be construed as directing the Commission to
23allocate any of the costs described in (i) or (ii) that are
24found to be appropriately included in the electric utility's
25delivery services rates to any particular customer group or
26geographic area in setting delivery services rates.

HB2640- 189 -LRB102 13765 SPS 19115 b
1 (d) The Commission shall establish charges, terms and
2conditions for delivery services that are just and reasonable
3and shall take into account customer impacts when establishing
4such charges. In establishing charges, terms and conditions
5for delivery services, the Commission shall take into account
6voltage level differences. A retail customer shall have the
7option to request to purchase electric service at any delivery
8service voltage reasonably and technically feasible from the
9electric facilities serving that customer's premises provided
10that there are no significant adverse impacts upon system
11reliability or system efficiency. A retail customer shall also
12have the option to request to purchase electric service at any
13point of delivery that is reasonably and technically feasible
14provided that there are no significant adverse impacts on
15system reliability or efficiency. Such requests shall not be
16unreasonably denied.
17 (e) Electric utilities shall recover the costs of
18installing, operating or maintaining facilities for the
19particular benefit of one or more delivery services customers,
20including without limitation any costs incurred in complying
21with a customer's request to be served at a different voltage
22level, directly from the retail customer or customers for
23whose benefit the costs were incurred, to the extent such
24costs are not recovered through the charges referred to in
25subsections (c) and (d) of this Section.
26 (f) An electric utility shall be entitled but not required

HB2640- 190 -LRB102 13765 SPS 19115 b
1to implement transition charges in conjunction with the
2offering of delivery services pursuant to Section 16-104. If
3an electric utility implements transition charges, it shall
4implement such charges for all delivery services customers and
5for all customers described in subsection (h), but shall not
6implement transition charges for power and energy that a
7retail customer takes from cogeneration or self-generation
8facilities located on that retail customer's premises, if such
9facilities meet the following criteria:
10 (i) the cogeneration or self-generation facilities
11 serve a single retail customer and are located on that
12 retail customer's premises (for purposes of this
13 subparagraph and subparagraph (ii), an industrial or
14 manufacturing retail customer and a third party contractor
15 that is served by such industrial or manufacturing
16 customer through such retail customer's own electrical
17 distribution facilities under the circumstances described
18 in subsection (vi) of the definition of "alternative
19 retail electric supplier" set forth in Section 16-102,
20 shall be considered a single retail customer);
21 (ii) the cogeneration or self-generation facilities
22 either (A) are sized pursuant to generally accepted
23 engineering standards for the retail customer's electrical
24 load at that premises (taking into account standby or
25 other reliability considerations related to that retail
26 customer's operations at that site) or (B) if the facility

HB2640- 191 -LRB102 13765 SPS 19115 b
1 is a cogeneration facility located on the retail
2 customer's premises, the retail customer is the thermal
3 host for that facility and the facility has been designed
4 to meet that retail customer's thermal energy requirements
5 resulting in electrical output beyond that retail
6 customer's electrical demand at that premises, comply with
7 the operating and efficiency standards applicable to
8 "qualifying facilities" specified in title 18 Code of
9 Federal Regulations Section 292.205 as in effect on the
10 effective date of this amendatory Act of 1999;
11 (iii) the retail customer on whose premises the
12 facilities are located either has an exclusive right to
13 receive, and corresponding obligation to pay for, all of
14 the electrical capacity of the facility, or in the case of
15 a cogeneration facility that has been designed to meet the
16 retail customer's thermal energy requirements at that
17 premises, an identified amount of the electrical capacity
18 of the facility, over a minimum 5-year period; and
19 (iv) if the cogeneration facility is sized for the
20 retail customer's thermal load at that premises but
21 exceeds the electrical load, any sales of excess power or
22 energy are made only at wholesale, are subject to the
23 jurisdiction of the Federal Energy Regulatory Commission,
24 and are not for the purpose of circumventing the
25 provisions of this subsection (f).
26If a generation facility located at a retail customer's

HB2640- 192 -LRB102 13765 SPS 19115 b
1premises does not meet the above criteria, an electric utility
2implementing transition charges shall implement a transition
3charge until December 31, 2006 for any power and energy taken
4by such retail customer from such facility as if such power and
5energy had been delivered by the electric utility. Provided,
6however, that an industrial retail customer that is taking
7power from a generation facility that does not meet the above
8criteria but that is located on such customer's premises will
9not be subject to a transition charge for the power and energy
10taken by such retail customer from such generation facility if
11the facility does not serve any other retail customer and
12either was installed on behalf of the customer and for its own
13use prior to January 1, 1997, or is both predominantly fueled
14by byproducts of such customer's manufacturing process at such
15premises and sells or offers an average of 300 megawatts or
16more of electricity produced from such generation facility
17into the wholesale market. Such charges shall be calculated as
18provided in Section 16-102, and shall be collected on each
19kilowatt-hour delivered under a delivery services tariff to a
20retail customer from the date the customer first takes
21delivery services until December 31, 2006 except as provided
22in subsection (h) of this Section. Provided, however, that an
23electric utility, other than an electric utility providing
24service to at least 1,000,000 customers in this State on
25January 1, 1999, shall be entitled to petition for entry of an
26order by the Commission authorizing the electric utility to

HB2640- 193 -LRB102 13765 SPS 19115 b
1implement transition charges for an additional period ending
2no later than December 31, 2008. The electric utility shall
3file its petition with supporting evidence no earlier than 16
4months, and no later than 12 months, prior to December 31,
52006. The Commission shall hold a hearing on the electric
6utility's petition and shall enter its order no later than 8
7months after the petition is filed. The Commission shall
8determine whether and to what extent the electric utility
9shall be authorized to implement transition charges for an
10additional period. The Commission may authorize the electric
11utility to implement transition charges for some or all of the
12additional period, and shall determine the mitigation factors
13to be used in implementing such transition charges; provided,
14that the Commission shall not authorize mitigation factors
15less than 110% of those in effect during the 12 months ended
16December 31, 2006. In making its determination, the Commission
17shall consider the following factors: the necessity to
18implement transition charges for an additional period in order
19to maintain the financial integrity of the electric utility;
20the prudence of the electric utility's actions in reducing its
21costs since the effective date of this amendatory Act of 1997;
22the ability of the electric utility to provide safe, adequate
23and reliable service to retail customers in its service area;
24and the impact on competition of allowing the electric utility
25to implement transition charges for the additional period.
26 (g) The electric utility shall file tariffs that establish

HB2640- 194 -LRB102 13765 SPS 19115 b
1the transition charges to be paid by each class of customers to
2the electric utility in conjunction with the provision of
3delivery services. The electric utility's tariffs shall define
4the classes of its customers for purposes of calculating
5transition charges. The electric utility's tariffs shall
6provide for the calculation of transition charges on a
7customer-specific basis for any retail customer whose average
8monthly maximum electrical demand on the electric utility's
9system during the 6 months with the customer's highest monthly
10maximum electrical demands equals or exceeds 3.0 megawatts for
11electric utilities having more than 1,000,000 customers, and
12for other electric utilities for any customer that has an
13average monthly maximum electrical demand on the electric
14utility's system of one megawatt or more, and (A) for which
15there exists data on the customer's usage during the 3 years
16preceding the date that the customer became eligible to take
17delivery services, or (B) for which there does not exist data
18on the customer's usage during the 3 years preceding the date
19that the customer became eligible to take delivery services,
20if in the electric utility's reasonable judgment there exists
21comparable usage information or a sufficient basis to develop
22such information, and further provided that the electric
23utility can require customers for which an individual
24calculation is made to sign contracts that set forth the
25transition charges to be paid by the customer to the electric
26utility pursuant to the tariff.

HB2640- 195 -LRB102 13765 SPS 19115 b
1 (h) An electric utility shall also be entitled to file
2tariffs that allow it to collect transition charges from
3retail customers in the electric utility's service area that
4do not take delivery services but that take electric power or
5energy from an alternative retail electric supplier or from an
6electric utility other than the electric utility in whose
7service area the customer is located. Such charges shall be
8calculated, in accordance with the definition of transition
9charges in Section 16-102, for the period of time that the
10customer would be obligated to pay transition charges if it
11were taking delivery services, except that no deduction for
12delivery services revenues shall be made in such calculation,
13and usage data from the customer's class shall be used where
14historical usage data is not available for the individual
15customer. The customer shall be obligated to pay such charges
16on a lump sum basis on or before the date on which the customer
17commences to take service from the alternative retail electric
18supplier or other electric utility, provided, that the
19electric utility in whose service area the customer is located
20shall offer the customer the option of signing a contract
21pursuant to which the customer pays such charges ratably over
22the period in which the charges would otherwise have applied.
23 (i) An electric utility shall be entitled to add to the
24bills of delivery services customers charges pursuant to
25Sections 9-221, 9-222 (except as provided in Section 9-222.1),
26and Section 16-114 of this Act, Section 5-5 of the Electricity

HB2640- 196 -LRB102 13765 SPS 19115 b
1Infrastructure Maintenance Fee Law, Section 6-5 of the
2Renewable Energy, Energy Efficiency, and Coal Resources
3Development Law of 1997, and Section 13 of the Energy
4Assistance Act.
5 (j) If a retail customer that obtains electric power and
6energy from cogeneration or self-generation facilities
7installed for its own use on or before January 1, 1997,
8subsequently takes service from an alternative retail electric
9supplier or an electric utility other than the electric
10utility in whose service area the customer is located for any
11portion of the customer's electric power and energy
12requirements formerly obtained from those facilities
13(including that amount purchased from the utility in lieu of
14such generation and not as standby power purchases, under a
15cogeneration displacement tariff in effect as of the effective
16date of this amendatory Act of 1997), the transition charges
17otherwise applicable pursuant to subsections (f), (g), or (h)
18of this Section shall not be applicable in any year to that
19portion of the customer's electric power and energy
20requirements formerly obtained from those facilities,
21provided, that for purposes of this subsection (j), such
22portion shall not exceed the average number of kilowatt-hours
23per year obtained from the cogeneration or self-generation
24facilities during the 3 years prior to the date on which the
25customer became eligible for delivery services, except as
26provided in subsection (f) of Section 16-110.

HB2640- 197 -LRB102 13765 SPS 19115 b
1 (k) The electric utility shall be entitled to recover
2through tariffed charges all of the costs associated with the
3purchase of zero emission credits from zero emission
4facilities to meet the requirements of subsection (d-5) of
5Section 1-75 of the Illinois Power Agency Act. Such costs
6shall include the costs of procuring the zero emission
7credits, as well as the reasonable costs that the utility
8incurs as part of the procurement processes and to implement
9and comply with plans and processes approved by the Commission
10under such subsection (d-5). The costs shall be allocated
11across all retail customers through a single, uniform cents
12per kilowatt-hour charge applicable to all retail customers,
13which shall appear as a separate line item on each customer's
14bill. Beginning June 1, 2017, the electric utility shall be
15entitled to recover through tariffed charges all of the costs
16associated with the purchase of renewable energy resources to
17meet the renewable energy resource standards of subsection (c)
18of Section 1-75 of the Illinois Power Agency Act, under
19procurement plans as approved in accordance with that Section
20and Section 16-111.5 of this Act. Such costs shall include the
21costs of procuring the renewable energy resources, as well as
22the reasonable costs that the utility incurs as part of the
23procurement processes and to implement and comply with plans
24and processes approved by the Commission under such Sections.
25The costs associated with the purchase of renewable energy
26resources shall be allocated across all retail customers in

HB2640- 198 -LRB102 13765 SPS 19115 b
1proportion to the amount of renewable energy resources the
2utility procures for such customers through a single, uniform
3cents per kilowatt-hour charge applicable to such retail
4customers, which shall appear as a separate line item on each
5such customer's bill.
6 Notwithstanding whether the Commission has approved the
7initial long-term renewable resources procurement plan as of
8June 1, 2017, an electric utility shall place new tariffed
9charges into effect beginning with the June 2017 monthly
10billing period, to the extent practicable, to begin recovering
11the costs of procuring renewable energy resources, as those
12charges are calculated under the limitations described in
13subparagraph (E) of paragraph (1) of subsection (c) of Section
141-75 of the Illinois Power Agency Act. Notwithstanding the
15date on which the utility places such new tariffed charges
16into effect, the utility shall be permitted to collect the
17charges under such tariff as if the tariff had been in effect
18beginning with the first day of the June 2017 monthly billing
19period. For the delivery years commencing June 1, 2017 through
20June 1, 2041, June 1, 2018, and June 1, 2019, the electric
21utility shall deposit into a separate interest bearing account
22of a financial institution the monies collected under the
23tariffed charges. Any interest earned shall be credited back
24to retail customers under the reconciliation proceeding
25provided for in this subsection (k), provided that the
26electric utility shall first be reimbursed from the interest

HB2640- 199 -LRB102 13765 SPS 19115 b
1for the administrative costs that it incurs to administer and
2manage the account. Any taxes due on the funds in the account,
3or interest earned on it, will be paid from the account or, if
4insufficient monies are available in the account, from the
5monies collected under the tariffed charges to recover the
6costs of procuring renewable energy resources. Monies
7deposited in the account shall be subject to the review,
8reconciliation, and true-up process described in this
9subsection (k) that is applicable to the funds collected and
10costs incurred for the procurement of renewable energy
11resources.
12 The electric utility shall be entitled to recover all of
13the costs identified in this subsection (k) through automatic
14adjustment clause tariffs applicable to all of the utility's
15retail customers that allow the electric utility to adjust its
16tariffed charges consistent with this subsection (k). The
17determination as to whether any excess funds were collected
18during a given delivery year for the purchase of renewable
19energy resources, and the crediting of any excess funds back
20to retail customers, shall not be made until after the close of
21the delivery year, which will ensure that the maximum amount
22of funds is available to implement the approved long-term
23renewable resources procurement plan during a given delivery
24year. The electric utility's collections under such automatic
25adjustment clause tariffs to recover the costs of renewable
26energy resources and zero emission credits from zero emission

HB2640- 200 -LRB102 13765 SPS 19115 b
1facilities shall be subject to separate annual review,
2reconciliation, and true-up against actual costs by the
3Commission under a procedure that shall be specified in the
4electric utility's automatic adjustment clause tariffs and
5that shall be approved by the Commission in connection with
6its approval of such tariffs. The procedure shall provide that
7any difference between the electric utility's collections
8under the automatic adjustment charges for an annual period
9and the electric utility's actual costs of renewable energy
10resources and zero emission credits from zero emission
11facilities for that same annual period shall be refunded to or
12collected from, as applicable, the electric utility's retail
13customers in subsequent periods.
14 Nothing in this subsection (k) is intended to affect,
15limit, or change the right of the electric utility to recover
16the costs associated with the procurement of renewable energy
17resources for periods commencing before, on, or after June 1,
182017, as otherwise provided in the Illinois Power Agency Act.
19 Notwithstanding anything to the contrary, the Commission
20shall not conduct an annual review, reconciliation, and
21true-up associated with renewable energy resources'
22collections and costs for the delivery years commencing June
231, 2017 through June 1, 2041, June 1, 2018, June 1, 2019, and
24June 1, 2020, and shall instead conduct a single review,
25reconciliation, and true-up associated with renewable energy
26resources' collections and costs for the 20-year 4-year period

HB2640- 201 -LRB102 13765 SPS 19115 b
1beginning June 1, 2017 and ending May 31, 2041 2021, provided
2that the review, reconciliation, and true-up shall not be
3initiated until after August 31, 2041 2021. During the 20-year
44-year period, the utility shall be permitted to collect and
5retain funds under this subsection (k) and to purchase
6renewable energy resources under an approved long-term
7renewable resources procurement plan using those funds
8regardless of the delivery year in which the funds were
9collected during the 20-year 4-year period.
10 If the amount of funds collected during the delivery year
11commencing June 1, 2017, exceeds the costs incurred during
12that delivery year, then up to half of this excess amount, as
13calculated on June 1, 2018, may be used to fund the programs
14under subsection (b) of Section 1-56 of the Illinois Power
15Agency Act in the same proportion the programs are funded
16under that subsection (b). However, any amount identified
17under this subsection (k) to fund programs under subsection
18(b) of Section 1-56 of the Illinois Power Agency Act shall be
19reduced if it exceeds the funding shortfall. For purposes of
20this Section, "funding shortfall" means the difference between
21$200,000,000 and the amount appropriated by the General
22Assembly to the Illinois Power Agency Renewable Energy
23Resources Fund during the period that commences on the
24effective date of this amendatory act of the 99th General
25Assembly and ends on August 1, 2018.
26 If the amount of funds collected during the delivery year

HB2640- 202 -LRB102 13765 SPS 19115 b
1commencing June 1, 2018, exceeds the costs incurred during
2that delivery year, then up to half of this excess amount, as
3calculated on June 1, 2019, may be used to fund the programs
4under subsection (b) of Section 1-56 of the Illinois Power
5Agency Act in the same proportion the programs are funded
6under that subsection (b). However, any amount identified
7under this subsection (k) to fund programs under subsection
8(b) of Section 1-56 of the Illinois Power Agency Act shall be
9reduced if it exceeds the funding shortfall.
10 If the amount of funds collected during the delivery year
11commencing June 1, 2019, exceeds the costs incurred during
12that delivery year, then up to half of this excess amount, as
13calculated on June 1, 2020, may be used to fund the programs
14under subsection (b) of Section 1-56 of the Illinois Power
15Agency Act in the same proportion the programs are funded
16under that subsection (b). However, any amount identified
17under this subsection (k) to fund programs under subsection
18(b) of Section 1-56 of the Illinois Power Agency Act shall be
19reduced if it exceeds the funding shortfall.
20 The funding available under this subsection (k), if any,
21for the programs described under subsection (b) of Section
221-56 of the Illinois Power Agency Act shall not reduce the
23amount of funding for the programs described in subparagraph
24(O) of paragraph (1) of subsection (c) of Section 1-75 of the
25Illinois Power Agency Act. If funding is available under this
26subsection (k) for programs described under subsection (b) of

HB2640- 203 -LRB102 13765 SPS 19115 b
1Section 1-56 of the Illinois Power Agency Act, then the
2long-term renewable resources plan shall provide for the
3Agency to procure contracts in an amount that does not exceed
4the funding, and the contracts approved by the Commission
5shall be executed by the applicable utility or utilities.
6 (l) A utility that has terminated any contract executed
7under subsection (d-5) of Section 1-75 of the Illinois Power
8Agency Act shall be entitled to recover any remaining balance
9associated with the purchase of zero emission credits prior to
10such termination, and such utility shall also apply a credit
11to its retail customer bills in the event of any
12over-collection.
13 (m)(1) An electric utility that recovers its costs of
14 procuring zero emission credits from zero emission
15 facilities through a cents-per-kilowatthour charge under
16 to subsection (k) of this Section shall be subject to the
17 requirements of this subsection (m). Notwithstanding
18 anything to the contrary, such electric utility shall,
19 beginning on April 30, 2018, and each April 30 thereafter
20 until April 30, 2026, calculate whether any reduction must
21 be applied to such cents-per-kilowatthour charge that is
22 paid by retail customers of the electric utility that are
23 exempt from subsections (a) through (j) of Section 8-103B
24 of this Act under subsection (l) of Section 8-103B. Such
25 charge shall be reduced for such customers for the next
26 delivery year commencing on June 1 based on the amount

HB2640- 204 -LRB102 13765 SPS 19115 b
1 necessary, if any, to limit the annual estimated average
2 net increase for the prior calendar year due to the future
3 energy investment costs to no more than 1.3% of 5.98 cents
4 per kilowatt-hour, which is the average amount paid per
5 kilowatthour for electric service during the year ending
6 December 31, 2015 by Illinois industrial retail customers,
7 as reported to the Edison Electric Institute.
8 The calculations required by this subsection (m) shall
9 be made only once for each year, and no subsequent rate
10 impact determinations shall be made.
11 (2) For purposes of this Section, "future energy
12 investment costs" shall be calculated by subtracting the
13 cents-per-kilowatthour charge identified in subparagraph
14 (A) of this paragraph (2) from the sum of the
15 cents-per-kilowatthour charges identified in subparagraph
16 (B) of this paragraph (2):
17 (A) The cents-per-kilowatthour charge identified
18 in the electric utility's tariff placed into effect
19 under Section 8-103 of the Public Utilities Act that,
20 on December 1, 2016, was applicable to those retail
21 customers that are exempt from subsections (a) through
22 (j) of Section 8-103B of this Act under subsection (l)
23 of Section 8-103B.
24 (B) The sum of the following
25 cents-per-kilowatthour charges applicable to those
26 retail customers that are exempt from subsections (a)

HB2640- 205 -LRB102 13765 SPS 19115 b
1 through (j) of Section 8-103B of this Act under
2 subsection (l) of Section 8-103B, provided that if one
3 or more of the following charges has been in effect and
4 applied to such customers for more than one calendar
5 year, then each charge shall be equal to the average of
6 the charges applied over a period that commences with
7 the calendar year ending December 31, 2017 and ends
8 with the most recently completed calendar year prior
9 to the calculation required by this subsection (m):
10 (i) the cents-per-kilowatthour charge to
11 recover the costs incurred by the utility under
12 subsection (d-5) of Section 1-75 of the Illinois
13 Power Agency Act, adjusted for any reductions
14 required under this subsection (m); and
15 (ii) the cents-per-kilowatthour charge to
16 recover the costs incurred by the utility under
17 Section 16-107.6 of the Public Utilities Act.
18 If no charge was applied for a given calendar year
19 under item (i) or (ii) of this subparagraph (B), then
20 the value of the charge for that year shall be zero.
21 (3) If a reduction is required by the calculation
22 performed under this subsection (m), then the amount of
23 the reduction shall be multiplied by the number of years
24 reflected in the averages calculated under subparagraph
25 (B) of paragraph (2) of this subsection (m). Such
26 reduction shall be applied to the cents-per-kilowatthour

HB2640- 206 -LRB102 13765 SPS 19115 b
1 charge that is applicable to those retail customers that
2 are exempt from subsections (a) through (j) of Section
3 8-103B of this Act under subsection (l) of Section 8-103B
4 beginning with the next delivery year commencing after the
5 date of the calculation required by this subsection (m).
6 (4) The electric utility shall file a notice with the
7 Commission on May 1 of 2018 and each May 1 thereafter until
8 May 1, 2026 containing the reduction, if any, which must
9 be applied for the delivery year which begins in the year
10 of the filing. The notice shall contain the calculations
11 made pursuant to this Section. By October 1 of each year
12 beginning in 2018, each electric utility shall notify the
13 Commission if it appears, based on an estimate of the
14 calculation required in this subsection (m), that a
15 reduction will be required in the next year.
16(Source: P.A. 99-906, eff. 6-1-17.)
17 (220 ILCS 5/16-111.5)
18 Sec. 16-111.5. Provisions relating to procurement.
19 (a) An electric utility that on December 31, 2005 served
20at least 100,000 customers in Illinois shall procure power and
21energy for its eligible retail customers in accordance with
22the applicable provisions set forth in Section 1-75 of the
23Illinois Power Agency Act and this Section. Beginning with the
24delivery year commencing on June 1, 2017, such electric
25utility shall also procure zero emission credits from zero

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1emission facilities in accordance with the applicable
2provisions set forth in Section 1-75 of the Illinois Power
3Agency Act, and, for years beginning on or after June 1, 2017,
4the utility shall procure renewable energy resources in
5accordance with the applicable provisions set forth in Section
61-75 of the Illinois Power Agency Act and this Section. A small
7multi-jurisdictional electric utility that on December 31,
82005 served less than 100,000 customers in Illinois may elect
9to procure power and energy for all or a portion of its
10eligible Illinois retail customers in accordance with the
11applicable provisions set forth in this Section and Section
121-75 of the Illinois Power Agency Act. This Section shall not
13apply to a small multi-jurisdictional utility until such time
14as a small multi-jurisdictional utility requests the Illinois
15Power Agency to prepare a procurement plan for its eligible
16retail customers. "Eligible retail customers" for the purposes
17of this Section means those retail customers that purchase
18power and energy from the electric utility under fixed-price
19bundled service tariffs, other than those retail customers
20whose service is declared or deemed competitive under Section
2116-113 and those other customer groups specified in this
22Section, including self-generating customers, customers
23electing hourly pricing, or those customers who are otherwise
24ineligible for fixed-price bundled tariff service. For those
25customers that are excluded from the procurement plan's
26electric supply service requirements, and the utility shall

HB2640- 208 -LRB102 13765 SPS 19115 b
1procure any supply requirements, including capacity, ancillary
2services, and hourly priced energy, in the applicable markets
3as needed to serve those customers, provided that the utility
4may include in its procurement plan load requirements for the
5load that is associated with those retail customers whose
6service has been declared or deemed competitive pursuant to
7Section 16-113 of this Act to the extent that those customers
8are purchasing power and energy during one of the transition
9periods identified in subsection (b) of Section 16-113 of this
10Act.
11 (b) A procurement plan shall be prepared for each electric
12utility consistent with the applicable requirements of the
13Illinois Power Agency Act and this Section. For purposes of
14this Section, Illinois electric utilities that are affiliated
15by virtue of a common parent company are considered to be a
16single electric utility. Small multi-jurisdictional utilities
17may request a procurement plan for a portion of or all of its
18Illinois load. Each procurement plan shall analyze the
19projected balance of supply and demand for those retail
20customers to be included in the plan's electric supply service
21requirements over a 5-year period, with the first planning
22year beginning on June 1 of the year following the year in
23which the plan is filed. The plan shall specifically identify
24the wholesale products to be procured following plan approval,
25and shall follow all the requirements set forth in the Public
26Utilities Act and all applicable State and federal laws,

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1statutes, rules, or regulations, as well as Commission orders.
2Nothing in this Section precludes consideration of contracts
3longer than 5 years and related forecast data. Unless
4specified otherwise in this Section, in the procurement plan
5or in the implementing tariff, any procurement occurring in
6accordance with this plan shall be competitively bid through a
7request for proposals process. Approval and implementation of
8the procurement plan shall be subject to review and approval
9by the Commission according to the provisions set forth in
10this Section. A procurement plan shall include each of the
11following components:
12 (1) Hourly load analysis. This analysis shall include:
13 (i) multi-year historical analysis of hourly
14 loads;
15 (ii) switching trends and competitive retail
16 market analysis;
17 (iii) known or projected changes to future loads;
18 and
19 (iv) growth forecasts by customer class.
20 (2) Analysis of the impact of any demand side and
21 renewable energy initiatives. This analysis shall include:
22 (i) the impact of demand response programs and
23 energy efficiency programs, both current and
24 projected; for small multi-jurisdictional utilities,
25 the impact of demand response and energy efficiency
26 programs approved pursuant to Section 8-408 of this

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1 Act, both current and projected; and
2 (ii) supply side needs that are projected to be
3 offset by purchases of renewable energy resources, if
4 any.
5 (3) A plan for meeting the expected load requirements
6 that will not be met through preexisting contracts. This
7 plan shall include:
8 (i) definitions of the different Illinois retail
9 customer classes for which supply is being purchased;
10 (ii) the proposed mix of demand-response products
11 for which contracts will be executed during the next
12 year. For small multi-jurisdictional electric
13 utilities that on December 31, 2005 served fewer than
14 100,000 customers in Illinois, these shall be defined
15 as demand-response products offered in an energy
16 efficiency plan approved pursuant to Section 8-408 of
17 this Act. The cost-effective demand-response measures
18 shall be procured whenever the cost is lower than
19 procuring comparable capacity products, provided that
20 such products shall:
21 (A) be procured by a demand-response provider
22 from those retail customers included in the plan's
23 electric supply service requirements;
24 (B) at least satisfy the demand-response
25 requirements of the regional transmission
26 organization market in which the utility's service

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1 territory is located, including, but not limited
2 to, any applicable capacity or dispatch
3 requirements;
4 (C) provide for customers' participation in
5 the stream of benefits produced by the
6 demand-response products;
7 (D) provide for reimbursement by the
8 demand-response provider of the utility for any
9 costs incurred as a result of the failure of the
10 supplier of such products to perform its
11 obligations thereunder; and
12 (E) meet the same credit requirements as apply
13 to suppliers of capacity, in the applicable
14 regional transmission organization market;
15 (iii) monthly forecasted system supply
16 requirements, including expected minimum, maximum, and
17 average values for the planning period;
18 (iv) the proposed mix and selection of standard
19 wholesale products for which contracts will be
20 executed during the next year, separately or in
21 combination, to meet that portion of its load
22 requirements not met through pre-existing contracts,
23 including but not limited to monthly 5 x 16 peak period
24 block energy, monthly off-peak wrap energy, monthly 7
25 x 24 energy, annual 5 x 16 energy, annual off-peak wrap
26 energy, annual 7 x 24 energy, monthly capacity, annual

HB2640- 212 -LRB102 13765 SPS 19115 b
1 capacity, peak load capacity obligations, capacity
2 purchase plan, and ancillary services;
3 (v) proposed term structures for each wholesale
4 product type included in the proposed procurement plan
5 portfolio of products; and
6 (vi) an assessment of the price risk, load
7 uncertainty, and other factors that are associated
8 with the proposed procurement plan; this assessment,
9 to the extent possible, shall include an analysis of
10 the following factors: contract terms, time frames for
11 securing products or services, fuel costs, weather
12 patterns, transmission costs, market conditions, and
13 the governmental regulatory environment; the proposed
14 procurement plan shall also identify alternatives for
15 those portfolio measures that are identified as having
16 significant price risk.
17 (4) Proposed procedures for balancing loads. The
18 procurement plan shall include, for load requirements
19 included in the procurement plan, the process for (i)
20 hourly balancing of supply and demand and (ii) the
21 criteria for portfolio re-balancing in the event of
22 significant shifts in load.
23 (5) Long-Term Renewable Resources Procurement Plan.
24 The Agency shall prepare a long-term renewable resources
25 procurement plan for the procurement of renewable energy
26 credits under Sections 1-56 and 1-75 of the Illinois Power

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1 Agency Act for delivery beginning in the 2017 delivery
2 year.
3 (i) The initial long-term renewable resources
4 procurement plan and all subsequent revisions shall be
5 subject to review and approval by the Commission. For
6 the purposes of this Section, "delivery year" has the
7 same meaning as in Section 1-10 of the Illinois Power
8 Agency Act. For purposes of this Section, "Agency"
9 shall mean the Illinois Power Agency.
10 (ii) The long-term renewable resources planning
11 process shall be conducted as follows:
12 (A) Electric utilities shall provide a range
13 of load forecasts to the Illinois Power Agency
14 within 45 days of the Agency's request for
15 forecasts, which request shall specify the length
16 and conditions for the forecasts including, but
17 not limited to, the quantity of distributed
18 generation expected to be interconnected for each
19 year.
20 (B) The Agency shall publish for comment the
21 initial long-term renewable resources procurement
22 plan no later than 120 days after the effective
23 date of this amendatory Act of the 99th General
24 Assembly and shall review, and may revise, the
25 plan at least every 2 years thereafter, with the
26 final plan issued no later than September 15 of

HB2640- 214 -LRB102 13765 SPS 19115 b
1 any particular year. To the extent practicable,
2 the Agency shall review and propose any revisions
3 to the long-term renewable energy resources
4 procurement plan in conjunction with the Agency's
5 other planning and approval processes conducted
6 under this Section. The initial long-term
7 renewable resources procurement 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

HB2640- 216 -LRB102 13765 SPS 19115 b
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

HB2640- 217 -LRB102 13765 SPS 19115 b
1 Section.
2 (iii) The Agency or third parties contracted by
3 the Agency shall implement all programs authorized by
4 the Commission in an approved long-term renewable
5 resources procurement plan without further review and
6 approval by the Commission. Any disputes regarding
7 implementation of the programs authorized in the Plan
8 shall be resolved in an expedited manner by the
9 Commission. Third parties shall not begin implementing
10 any programs or receive any payment under this Section
11 until the Commission has approved the contract or
12 contracts under the process authorized by the
13 Commission in item (D) of subparagraph (ii) of
14 paragraph (5) of this subsection (b) and the third
15 party and the Agency or utility, as applicable, have
16 executed the contract. For those renewable energy
17 credits subject to procurement through a competitive
18 bid process under the plan or under the initial
19 forward procurements for wind and solar resources
20 described in subparagraph (G) of paragraph (1) of
21 subsection (c) of Section 1-75 of the Illinois Power
22 Agency Act, the Agency shall follow the procurement
23 process specified in the provisions relating to
24 electricity procurement in subsections (e) through (i)
25 of this Section.
26 (iv) An electric utility shall recover its costs

HB2640- 218 -LRB102 13765 SPS 19115 b
1 associated with the procurement of renewable energy
2 credits under this Section through an automatic
3 adjustment clause tariff under subsection (k) of
4 Section 16-108 of this Act. A utility shall not be
5 required to advance any payment or pay any amounts
6 under this Section that exceed the actual amount of
7 revenues collected by the utility under paragraph (6)
8 of subsection (c) of Section 1-75 of the Illinois
9 Power Agency Act and subsection (k) of Section 16-108
10 of this Act, and contracts executed under this Section
11 shall expressly incorporate this limitation.
12 (v) For the public interest, safety, and welfare,
13 the Agency and the Commission may adopt rules to carry
14 out the provisions of this Section on an emergency
15 basis immediately following the effective date of this
16 amendatory Act of the 99th General Assembly.
17 (vi) On or before July 1 of each year, the
18 Commission shall hold an informal hearing for the
19 purpose of receiving comments on the prior year's
20 procurement process and any recommendations for
21 change.
22 (vii) As part of the long-term renewable resources
23 procurement plan for the 2021 delivery year or within
24 30 days after the effective date of this amendatory
25 Act of the 102nd General Assembly, whichever comes
26 first, and each revision thereafter, the Illinois

HB2640- 219 -LRB102 13765 SPS 19115 b
1 Power Agency and its consultant or consultants shall
2 engage stakeholders in a retrospective evaluation of
3 the design and implementation of the Adjustable Block
4 program. Specifically, the evaluation shall address:
5 (A) Interdependencies between the Adjustable
6 Block program and interconnection standards,
7 tariffs, and processes addressed or directed in
8 Section 16-107.5.
9 (B) Revisions to the Adjustable Block program
10 and interconnection standards, tariffs, and
11 processes that will facilitate implementation of
12 the Adjustable Block program.
13 (C) Ensuring that the objectives stated in
14 subparagraph (K) of paragraph (1) of subsection
15 (c) of Section 1-75 of the Illinois Power Agency
16 Act, as well as subsection (h) of Section 16-107.5
17 of this Act are met.
18 The results of this evaluation shall be used by
19 the Illinois Power Agency to amend the Adjustable
20 Block program accordingly.
21 (c) The procurement process set forth in Section 1-75 of
22the Illinois Power Agency Act and subsection (e) of this
23Section shall be administered by a procurement administrator
24and monitored by a procurement monitor.
25 (1) The procurement administrator shall:
26 (i) design the final procurement process in

HB2640- 220 -LRB102 13765 SPS 19115 b
1 accordance with Section 1-75 of the Illinois Power
2 Agency Act and subsection (e) of this Section
3 following Commission approval of the procurement plan;
4 (ii) develop benchmarks in accordance with
5 subsection (e)(3) to be used to evaluate bids; these
6 benchmarks shall be submitted to the Commission for
7 review and approval on a confidential basis prior to
8 the procurement event;
9 (iii) serve as the interface between the electric
10 utility and suppliers;
11 (iv) manage the bidder pre-qualification and
12 registration process;
13 (v) obtain the electric utilities' agreement to
14 the final form of all supply contracts and credit
15 collateral agreements;
16 (vi) administer the request for proposals process;
17 (vii) have the discretion to negotiate to
18 determine whether bidders are willing to lower the
19 price of bids that meet the benchmarks approved by the
20 Commission; any post-bid negotiations with bidders
21 shall be limited to price only and shall be completed
22 within 24 hours after opening the sealed bids and
23 shall be conducted in a fair and unbiased manner; in
24 conducting the negotiations, there shall be no
25 disclosure of any information derived from proposals
26 submitted by competing bidders; if information is

HB2640- 221 -LRB102 13765 SPS 19115 b
1 disclosed to any bidder, it shall be provided to all
2 competing bidders;
3 (viii) maintain confidentiality of supplier and
4 bidding information in a manner consistent with all
5 applicable laws, rules, regulations, and tariffs;
6 (ix) submit a confidential report to the
7 Commission recommending acceptance or rejection of
8 bids;
9 (x) notify the utility of contract counterparties
10 and contract specifics; and
11 (xi) administer related contingency procurement
12 events.
13 (2) The procurement monitor, who shall be retained by
14 the Commission, shall:
15 (i) monitor interactions among the procurement
16 administrator, suppliers, and utility;
17 (ii) monitor and report to the Commission on the
18 progress of the procurement process;
19 (iii) provide an independent confidential report
20 to the Commission regarding the results of the
21 procurement event;
22 (iv) assess compliance with the procurement plans
23 approved by the Commission for each utility that on
24 December 31, 2005 provided electric service to at
25 least 100,000 customers in Illinois and for each small
26 multi-jurisdictional utility that on December 31, 2005

HB2640- 222 -LRB102 13765 SPS 19115 b
1 served less than 100,000 customers in Illinois;
2 (v) preserve the confidentiality of supplier and
3 bidding information in a manner consistent with all
4 applicable laws, rules, regulations, and tariffs;
5 (vi) provide expert advice to the Commission and
6 consult with the procurement administrator regarding
7 issues related to procurement process design, rules,
8 protocols, and policy-related matters; and
9 (vii) consult with the procurement administrator
10 regarding the development and use of benchmark
11 criteria, standard form contracts, credit policies,
12 and bid documents.
13 (d) Except as provided in subsection (j), the planning
14process shall be conducted as follows:
15 (1) Beginning in 2008, each Illinois utility procuring
16 power pursuant to this Section shall annually provide a
17 range of load forecasts to the Illinois Power Agency by
18 July 15 of each year, or such other date as may be required
19 by the Commission or Agency. The load forecasts shall
20 cover the 5-year procurement planning period for the next
21 procurement plan and shall include hourly data
22 representing a high-load, low-load, and expected-load
23 scenario for the load of those retail customers included
24 in the plan's electric supply service requirements. The
25 utility shall provide supporting data and assumptions for
26 each of the scenarios.

HB2640- 223 -LRB102 13765 SPS 19115 b
1 (2) Beginning in 2008, the Illinois Power Agency shall
2 prepare a procurement plan by August 15th of each year, or
3 such other date as may be required by the Commission. The
4 procurement plan shall identify the portfolio of
5 demand-response and power and energy products to be
6 procured. Cost-effective demand-response measures shall be
7 procured as set forth in item (iii) of subsection (b) of
8 this Section. Copies of the procurement plan shall be
9 posted and made publicly available on the Agency's and
10 Commission's websites, and copies shall also be provided
11 to each affected electric utility. An affected utility
12 shall have 30 days following the date of posting to
13 provide comment to the Agency on the procurement plan.
14 Other interested entities also may comment on the
15 procurement plan. All comments submitted to the Agency
16 shall be specific, supported by data or other detailed
17 analyses, and, if objecting to all or a portion of the
18 procurement plan, accompanied by specific alternative
19 wording or proposals. All comments shall be posted on the
20 Agency's and Commission's websites. During this 30-day
21 comment period, the Agency shall hold at least one public
22 hearing within each utility's service area for the purpose
23 of receiving public comment on the procurement plan.
24 Within 14 days following the end of the 30-day review
25 period, the Agency shall revise the procurement plan as
26 necessary based on the comments received and file the

HB2640- 224 -LRB102 13765 SPS 19115 b
1 procurement plan with the Commission and post the
2 procurement plan on the websites.
3 (3) Within 5 days after the filing of the procurement
4 plan, any person objecting to the procurement plan shall
5 file an objection with the Commission. Within 10 days
6 after the filing, the Commission shall determine whether a
7 hearing is necessary. The Commission shall enter its order
8 confirming or modifying the procurement plan within 90
9 days after the filing of the procurement plan by the
10 Illinois Power Agency.
11 (4) The Commission shall approve the procurement plan,
12 including expressly the forecast used in the procurement
13 plan, if the Commission determines that it will ensure
14 adequate, reliable, affordable, efficient, and
15 environmentally sustainable electric service at the lowest
16 total cost over time, taking into account any benefits of
17 price stability.
18 (e) The procurement process shall include each of the
19following components:
20 (1) Solicitation, pre-qualification, and registration
21 of bidders. The procurement administrator shall
22 disseminate information to potential bidders to promote a
23 procurement event, notify potential bidders that the
24 procurement administrator may enter into a post-bid price
25 negotiation with bidders that meet the applicable
26 benchmarks, provide supply requirements, and otherwise

HB2640- 225 -LRB102 13765 SPS 19115 b
1 explain the competitive procurement process. In addition
2 to such other publication as the procurement administrator
3 determines is appropriate, this information shall be
4 posted on the Illinois Power Agency's and the Commission's
5 websites. The procurement administrator shall also
6 administer the prequalification process, including
7 evaluation of credit worthiness, compliance with
8 procurement rules, and agreement to the standard form
9 contract developed pursuant to paragraph (2) of this
10 subsection (e). The procurement administrator shall then
11 identify and register bidders to participate in the
12 procurement event.
13 (2) Standard contract forms and credit terms and
14 instruments. The procurement administrator, in
15 consultation with the utilities, the Commission, and other
16 interested parties and subject to Commission oversight,
17 shall develop and provide standard contract forms for the
18 supplier contracts that meet generally accepted industry
19 practices. Standard credit terms and instruments that meet
20 generally accepted industry practices shall be similarly
21 developed. The procurement administrator shall make
22 available to the Commission all written comments it
23 receives on the contract forms, credit terms, or
24 instruments. If the procurement administrator cannot reach
25 agreement with the applicable electric utility as to the
26 contract terms and conditions, the procurement

HB2640- 226 -LRB102 13765 SPS 19115 b
1 administrator must notify the Commission of any disputed
2 terms and the Commission shall resolve the dispute. The
3 terms of the contracts shall not be subject to negotiation
4 by winning bidders, and the bidders must agree to the
5 terms of the contract in advance so that winning bids are
6 selected solely on the basis of price.
7 (3) Establishment of a market-based price benchmark.
8 As part of the development of the procurement process, the
9 procurement administrator, in consultation with the
10 Commission staff, Agency staff, and the procurement
11 monitor, shall establish benchmarks for evaluating the
12 final prices in the contracts for each of the products
13 that will be procured through the procurement process. The
14 benchmarks shall be based on price data for similar
15 products for the same delivery period and same delivery
16 hub, or other delivery hubs after adjusting for that
17 difference. The price benchmarks may also be adjusted to
18 take into account differences between the information
19 reflected in the underlying data sources and the specific
20 products and procurement process being used to procure
21 power for the Illinois utilities. The benchmarks shall be
22 confidential but shall be provided to, and will be subject
23 to Commission review and approval, prior to a procurement
24 event.
25 (4) Request for proposals competitive procurement
26 process. The procurement administrator shall design and

HB2640- 227 -LRB102 13765 SPS 19115 b
1 issue a request for proposals to supply electricity in
2 accordance with each utility's procurement plan, as
3 approved by the Commission. The request for proposals
4 shall set forth a procedure for sealed, binding commitment
5 bidding with pay-as-bid settlement, and provision for
6 selection of bids on the basis of price.
7 (5) A plan for implementing contingencies in the event
8 of supplier default or failure of the procurement process
9 to fully meet the expected load requirement due to
10 insufficient supplier participation, Commission rejection
11 of results, or any other cause.
12 (i) Event of supplier default: In the event of
13 supplier default, the utility shall review the
14 contract of the defaulting supplier to determine if
15 the amount of supply is 200 megawatts or greater, and
16 if there are more than 60 days remaining of the
17 contract term. If both of these conditions are met,
18 and the default results in termination of the
19 contract, the utility shall immediately notify the
20 Illinois Power Agency that a request for proposals
21 must be issued to procure replacement power, and the
22 procurement administrator shall run an additional
23 procurement event. If the contracted supply of the
24 defaulting supplier is less than 200 megawatts or
25 there are less than 60 days remaining of the contract
26 term, the utility shall procure power and energy from

HB2640- 228 -LRB102 13765 SPS 19115 b
1 the applicable regional transmission organization
2 market, including ancillary services, capacity, and
3 day-ahead or real time energy, or both, for the
4 duration of the contract term to replace the
5 contracted supply; provided, however, that if a needed
6 product is not available through the regional
7 transmission organization market it shall be purchased
8 from the wholesale market.
9 (ii) Failure of the procurement process to fully
10 meet the expected load requirement: If the procurement
11 process fails to fully meet the expected load
12 requirement due to insufficient supplier participation
13 or due to a Commission rejection of the procurement
14 results, the procurement administrator, the
15 procurement monitor, and the Commission staff shall
16 meet within 10 days to analyze potential causes of low
17 supplier interest or causes for the Commission
18 decision. If changes are identified that would likely
19 result in increased supplier participation, or that
20 would address concerns causing the Commission to
21 reject the results of the prior procurement event, the
22 procurement administrator may implement those changes
23 and rerun the request for proposals process according
24 to a schedule determined by those parties and
25 consistent with Section 1-75 of the Illinois Power
26 Agency Act and this subsection. In any event, a new

HB2640- 229 -LRB102 13765 SPS 19115 b
1 request for proposals process shall be implemented by
2 the procurement administrator within 90 days after the
3 determination that the procurement process has failed
4 to fully meet the expected load requirement.
5 (iii) In all cases where there is insufficient
6 supply provided under contracts awarded through the
7 procurement process to fully meet the electric
8 utility's load requirement, the utility shall meet the
9 load requirement by procuring power and energy from
10 the applicable regional transmission organization
11 market, including ancillary services, capacity, and
12 day-ahead or real time energy, or both; provided,
13 however, that if a needed product is not available
14 through the regional transmission organization market
15 it shall be purchased from the wholesale market.
16 (6) The procurement process described in this
17 subsection is exempt from the requirements of the Illinois
18 Procurement Code, pursuant to Section 20-10 of that Code.
19 (f) Within 2 business days after opening the sealed bids,
20the procurement administrator shall submit a confidential
21report to the Commission. The report shall contain the results
22of the bidding for each of the products along with the
23procurement administrator's recommendation for the acceptance
24and rejection of bids based on the price benchmark criteria
25and other factors observed in the process. The procurement
26monitor also shall submit a confidential report to the

HB2640- 230 -LRB102 13765 SPS 19115 b
1Commission within 2 business days after opening the sealed
2bids. The report shall contain the procurement monitor's
3assessment of bidder behavior in the process as well as an
4assessment of the procurement administrator's compliance with
5the procurement process and rules. The Commission shall review
6the confidential reports submitted by the procurement
7administrator and procurement monitor, and shall accept or
8reject the recommendations of the procurement administrator
9within 2 business days after receipt of the reports.
10 (g) Within 3 business days after the Commission decision
11approving the results of a procurement event, the utility
12shall enter into binding contractual arrangements with the
13winning suppliers using the standard form contracts; except
14that the utility shall not be required either directly or
15indirectly to execute the contracts if a tariff that is
16consistent with subsection (l) of this Section has not been
17approved and placed into effect for that utility.
18 (h) The names of the successful bidders and the load
19weighted average of the winning bid prices for each contract
20type and for each contract term shall be made available to the
21public at the time of Commission approval of a procurement
22event. The Commission, the procurement monitor, the
23procurement administrator, the Illinois Power Agency, and all
24participants in the procurement process shall maintain the
25confidentiality of all other supplier and bidding information
26in a manner consistent with all applicable laws, rules,

HB2640- 231 -LRB102 13765 SPS 19115 b
1regulations, and tariffs. Confidential information, including
2the confidential reports submitted by the procurement
3administrator and procurement monitor pursuant to subsection
4(f) of this Section, shall not be made publicly available and
5shall not be discoverable by any party in any proceeding,
6absent a compelling demonstration of need, nor shall those
7reports be admissible in any proceeding other than one for law
8enforcement purposes.
9 (i) Within 2 business days after a Commission decision
10approving the results of a procurement event or such other
11date as may be required by the Commission from time to time,
12the utility shall file for informational purposes with the
13Commission its actual or estimated retail supply charges, as
14applicable, by customer supply group reflecting the costs
15associated with the procurement and computed in accordance
16with the tariffs filed pursuant to subsection (l) of this
17Section and approved by the Commission.
18 (j) Within 60 days following August 28, 2007 (the
19effective date of Public Act 95-481), each electric utility
20that on December 31, 2005 provided electric service to at
21least 100,000 customers in Illinois shall prepare and file
22with the Commission an initial procurement plan, which shall
23conform in all material respects to the requirements of the
24procurement plan set forth in subsection (b); provided,
25however, that the Illinois Power Agency Act shall not apply to
26the initial procurement plan prepared pursuant to this

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1subsection. The initial procurement plan shall identify the
2portfolio of power and energy products to be procured and
3delivered for the period June 2008 through May 2009, and shall
4identify the proposed procurement administrator, who shall
5have the same experience and expertise as is required of a
6procurement administrator hired pursuant to Section 1-75 of
7the Illinois Power Agency Act. Copies of the procurement plan
8shall be posted and made publicly available on the
9Commission's website. The initial procurement plan may include
10contracts for renewable resources that extend beyond May 2009.
11 (i) Within 14 days following filing of the initial
12 procurement plan, any person may file a detailed objection
13 with the Commission contesting the procurement plan
14 submitted by the electric utility. All objections to the
15 electric utility's plan shall be specific, supported by
16 data or other detailed analyses. The electric utility may
17 file a response to any objections to its procurement plan
18 within 7 days after the date objections are due to be
19 filed. Within 7 days after the date the utility's response
20 is due, the Commission shall determine whether a hearing
21 is necessary. If it determines that a hearing is
22 necessary, it shall require the hearing to be completed
23 and issue an order on the procurement plan within 60 days
24 after the filing of the procurement plan by the electric
25 utility.
26 (ii) The order shall approve or modify the procurement

HB2640- 233 -LRB102 13765 SPS 19115 b
1 plan, approve an independent procurement administrator,
2 and approve or modify the electric utility's tariffs that
3 are proposed with the initial procurement plan. The
4 Commission shall approve the procurement plan if the
5 Commission determines that it will ensure adequate,
6 reliable, affordable, efficient, and environmentally
7 sustainable electric service at the lowest total cost over
8 time, taking into account any benefits of price sta