101ST GENERAL ASSEMBLY
State of Illinois
2019 and 2020
HB2966

 

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.


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FISCAL NOTE ACT MAY APPLY

 

 

A BILL FOR

 

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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 changing Section 5-45 as follows:
 
6    (5 ILCS 100/5-45)  (from Ch. 127, par. 1005-45)
7    Sec. 5-45. Emergency rulemaking.
8    (a) "Emergency" means the existence of any situation that
9any agency finds reasonably constitutes a threat to the public
10interest, safety, or welfare.
11    (b) If any agency finds that an emergency exists that
12requires adoption of a rule upon fewer days than is required by
13Section 5-40 and states in writing its reasons for that
14finding, the agency may adopt an emergency rule without prior
15notice or hearing upon filing a notice of emergency rulemaking
16with the Secretary of State under Section 5-70. The notice
17shall include the text of the emergency rule and shall be
18published in the Illinois Register. Consent orders or other
19court orders adopting settlements negotiated by an agency may
20be adopted under this Section. Subject to applicable
21constitutional or statutory provisions, an emergency rule
22becomes effective immediately upon filing under Section 5-65 or
23at a stated date less than 10 days thereafter. The agency's

 

 

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1finding and a statement of the specific reasons for the finding
2shall be filed with the rule. The agency shall take reasonable
3and appropriate measures to make emergency rules known to the
4persons who may be affected by them.
5    (c) An emergency rule may be effective for a period of not
6longer than 150 days, but the agency's authority to adopt an
7identical rule under Section 5-40 is not precluded. No
8emergency rule may be adopted more than once in any 24-month
9period, except that this limitation on the number of emergency
10rules that may be adopted in a 24-month period does not apply
11to (i) emergency rules that make additions to and deletions
12from the Drug Manual under Section 5-5.16 of the Illinois
13Public Aid Code or the generic drug formulary under Section
143.14 of the Illinois Food, Drug and Cosmetic Act, (ii)
15emergency rules adopted by the Pollution Control Board before
16July 1, 1997 to implement portions of the Livestock Management
17Facilities Act, (iii) emergency rules adopted by the Illinois
18Department of Public Health under subsections (a) through (i)
19of Section 2 of the Department of Public Health Act when
20necessary to protect the public's health, (iv) emergency rules
21adopted pursuant to subsection (n) of this Section, (v)
22emergency rules adopted pursuant to subsection (o) of this
23Section, or (vi) emergency rules adopted pursuant to subsection
24(c-5) of this Section. Two or more emergency rules having
25substantially the same purpose and effect shall be deemed to be
26a single rule for purposes of this Section.

 

 

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1    (c-5) To facilitate the maintenance of the program of group
2health benefits provided to annuitants, survivors, and retired
3employees under the State Employees Group Insurance Act of
41971, rules to alter the contributions to be paid by the State,
5annuitants, survivors, retired employees, or any combination
6of those entities, for that program of group health benefits,
7shall be adopted as emergency rules. The adoption of those
8rules shall be considered an emergency and necessary for the
9public interest, safety, and welfare.
10    (d) In order to provide for the expeditious and timely
11implementation of the State's fiscal year 1999 budget,
12emergency rules to implement any provision of Public Act 90-587
13or 90-588 or any other budget initiative for fiscal year 1999
14may be adopted in accordance with this Section by the agency
15charged with administering that provision or initiative,
16except that the 24-month limitation on the adoption of
17emergency rules and the provisions of Sections 5-115 and 5-125
18do not apply to rules adopted under this subsection (d). The
19adoption of emergency rules authorized by this subsection (d)
20shall be deemed to be necessary for the public interest,
21safety, and welfare.
22    (e) In order to provide for the expeditious and timely
23implementation of the State's fiscal year 2000 budget,
24emergency rules to implement any provision of Public Act 91-24
25or any other budget initiative for fiscal year 2000 may be
26adopted in accordance with this Section by the agency charged

 

 

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1with administering that provision or initiative, except that
2the 24-month limitation on the adoption of emergency rules and
3the provisions of Sections 5-115 and 5-125 do not apply to
4rules adopted under this subsection (e). The adoption of
5emergency rules authorized by this subsection (e) shall be
6deemed to be necessary for the public interest, safety, and
7welfare.
8    (f) In order to provide for the expeditious and timely
9implementation of the State's fiscal year 2001 budget,
10emergency rules to implement any provision of Public Act 91-712
11or any other budget initiative for fiscal year 2001 may be
12adopted in accordance with this Section by the agency charged
13with administering that provision or initiative, except that
14the 24-month limitation on the adoption of emergency rules and
15the provisions of Sections 5-115 and 5-125 do not apply to
16rules adopted under this subsection (f). The adoption of
17emergency rules authorized by this subsection (f) shall be
18deemed to be necessary for the public interest, safety, and
19welfare.
20    (g) In order to provide for the expeditious and timely
21implementation of the State's fiscal year 2002 budget,
22emergency rules to implement any provision of Public Act 92-10
23or any other budget initiative for fiscal year 2002 may be
24adopted in accordance with this Section by the agency charged
25with administering that provision or initiative, except that
26the 24-month limitation on the adoption of emergency rules and

 

 

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1the provisions of Sections 5-115 and 5-125 do not apply to
2rules adopted under this subsection (g). The adoption of
3emergency rules authorized by this subsection (g) shall be
4deemed to be necessary for the public interest, safety, and
5welfare.
6    (h) In order to provide for the expeditious and timely
7implementation of the State's fiscal year 2003 budget,
8emergency rules to implement any provision of Public Act 92-597
9or any other budget initiative for fiscal year 2003 may be
10adopted in accordance with this Section by the agency charged
11with administering that provision or initiative, except that
12the 24-month limitation on the adoption of emergency rules and
13the provisions of Sections 5-115 and 5-125 do not apply to
14rules adopted under this subsection (h). The adoption of
15emergency rules authorized by this subsection (h) shall be
16deemed to be necessary for the public interest, safety, and
17welfare.
18    (i) In order to provide for the expeditious and timely
19implementation of the State's fiscal year 2004 budget,
20emergency rules to implement any provision of Public Act 93-20
21or any other budget initiative for fiscal year 2004 may be
22adopted in accordance with this Section by the agency charged
23with administering that provision or initiative, except that
24the 24-month limitation on the adoption of emergency rules and
25the provisions of Sections 5-115 and 5-125 do not apply to
26rules adopted under this subsection (i). The adoption of

 

 

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1emergency rules authorized by this subsection (i) shall be
2deemed to be necessary for the public interest, safety, and
3welfare.
4    (j) In order to provide for the expeditious and timely
5implementation of the provisions of the State's fiscal year
62005 budget as provided under the Fiscal Year 2005 Budget
7Implementation (Human Services) Act, emergency rules to
8implement any provision of the Fiscal Year 2005 Budget
9Implementation (Human Services) Act may be adopted in
10accordance with this Section by the agency charged with
11administering that provision, except that the 24-month
12limitation on the adoption of emergency rules and the
13provisions of Sections 5-115 and 5-125 do not apply to rules
14adopted under this subsection (j). The Department of Public Aid
15may also adopt rules under this subsection (j) necessary to
16administer the Illinois Public Aid Code and the Children's
17Health Insurance Program Act. The adoption of emergency rules
18authorized by this subsection (j) shall be deemed to be
19necessary for the public interest, safety, and welfare.
20    (k) In order to provide for the expeditious and timely
21implementation of the provisions of the State's fiscal year
222006 budget, emergency rules to implement any provision of
23Public Act 94-48 or any other budget initiative for fiscal year
242006 may be adopted in accordance with this Section by the
25agency charged with administering that provision or
26initiative, except that the 24-month limitation on the adoption

 

 

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1of emergency rules and the provisions of Sections 5-115 and
25-125 do not apply to rules adopted under this subsection (k).
3The Department of Healthcare and Family Services may also adopt
4rules under this subsection (k) necessary to administer the
5Illinois Public Aid Code, the Senior Citizens and Persons with
6Disabilities Property Tax Relief Act, the Senior Citizens and
7Disabled Persons Prescription Drug Discount Program Act (now
8the Illinois Prescription Drug Discount Program Act), and the
9Children's Health Insurance Program Act. The adoption of
10emergency rules authorized by this subsection (k) shall be
11deemed to be necessary for the public interest, safety, and
12welfare.
13    (l) In order to provide for the expeditious and timely
14implementation of the provisions of the State's fiscal year
152007 budget, the Department of Healthcare and Family Services
16may adopt emergency rules during fiscal year 2007, including
17rules effective July 1, 2007, in accordance with this
18subsection to the extent necessary to administer the
19Department's responsibilities with respect to amendments to
20the State plans and Illinois waivers approved by the federal
21Centers for Medicare and Medicaid Services necessitated by the
22requirements of Title XIX and Title XXI of the federal Social
23Security Act. The adoption of emergency rules authorized by
24this subsection (l) shall be deemed to be necessary for the
25public interest, safety, and welfare.
26    (m) In order to provide for the expeditious and timely

 

 

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1implementation of the provisions of the State's fiscal year
22008 budget, the Department of Healthcare and Family Services
3may adopt emergency rules during fiscal year 2008, including
4rules effective July 1, 2008, in accordance with this
5subsection to the extent necessary to administer the
6Department's responsibilities with respect to amendments to
7the State plans and Illinois waivers approved by the federal
8Centers for Medicare and Medicaid Services necessitated by the
9requirements of Title XIX and Title XXI of the federal Social
10Security Act. The adoption of emergency rules authorized by
11this subsection (m) shall be deemed to be necessary for the
12public interest, safety, and welfare.
13    (n) In order to provide for the expeditious and timely
14implementation of the provisions of the State's fiscal year
152010 budget, emergency rules to implement any provision of
16Public Act 96-45 or any other budget initiative authorized by
17the 96th General Assembly for fiscal year 2010 may be adopted
18in accordance with this Section by the agency charged with
19administering that provision or initiative. The adoption of
20emergency rules authorized by this subsection (n) shall be
21deemed to be necessary for the public interest, safety, and
22welfare. The rulemaking authority granted in this subsection
23(n) shall apply only to rules promulgated during Fiscal Year
242010.
25    (o) In order to provide for the expeditious and timely
26implementation of the provisions of the State's fiscal year

 

 

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12011 budget, emergency rules to implement any provision of
2Public Act 96-958 or any other budget initiative authorized by
3the 96th General Assembly for fiscal year 2011 may be adopted
4in accordance with this Section by the agency charged with
5administering that provision or initiative. The adoption of
6emergency rules authorized by this subsection (o) is deemed to
7be necessary for the public interest, safety, and welfare. The
8rulemaking authority granted in this subsection (o) applies
9only to rules promulgated on or after July 1, 2010 (the
10effective date of Public Act 96-958) through June 30, 2011.
11    (p) In order to provide for the expeditious and timely
12implementation of the provisions of Public Act 97-689,
13emergency rules to implement any provision of Public Act 97-689
14may be adopted in accordance with this subsection (p) by the
15agency charged with administering that provision or
16initiative. The 150-day limitation of the effective period of
17emergency rules does not apply to rules adopted under this
18subsection (p), and the effective period may continue through
19June 30, 2013. The 24-month limitation on the adoption of
20emergency rules does not apply to rules adopted under this
21subsection (p). The adoption of emergency rules authorized by
22this subsection (p) is deemed to be necessary for the public
23interest, safety, and welfare.
24    (q) In order to provide for the expeditious and timely
25implementation of the provisions of Articles 7, 8, 9, 11, and
2612 of Public Act 98-104, emergency rules to implement any

 

 

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1provision of Articles 7, 8, 9, 11, and 12 of Public Act 98-104
2may be adopted in accordance with this subsection (q) by the
3agency charged with administering that provision or
4initiative. The 24-month limitation on the adoption of
5emergency rules does not apply to rules adopted under this
6subsection (q). The adoption of emergency rules authorized by
7this subsection (q) is deemed to be necessary for the public
8interest, safety, and welfare.
9    (r) In order to provide for the expeditious and timely
10implementation of the provisions of Public Act 98-651,
11emergency rules to implement Public Act 98-651 may be adopted
12in accordance with this subsection (r) by the Department of
13Healthcare and Family Services. The 24-month limitation on the
14adoption of emergency rules does not apply to rules adopted
15under this subsection (r). The adoption of emergency rules
16authorized by this subsection (r) is deemed to be necessary for
17the public interest, safety, and welfare.
18    (s) In order to provide for the expeditious and timely
19implementation of the provisions of Sections 5-5b.1 and 5A-2 of
20the Illinois Public Aid Code, emergency rules to implement any
21provision of Section 5-5b.1 or Section 5A-2 of the Illinois
22Public Aid Code may be adopted in accordance with this
23subsection (s) by the Department of Healthcare and Family
24Services. The rulemaking authority granted in this subsection
25(s) shall apply only to those rules adopted prior to July 1,
262015. Notwithstanding any other provision of this Section, any

 

 

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1emergency rule adopted under this subsection (s) shall only
2apply to payments made for State fiscal year 2015. The adoption
3of emergency rules authorized by this subsection (s) is deemed
4to be necessary for the public interest, safety, and welfare.
5    (t) In order to provide for the expeditious and timely
6implementation of the provisions of Article II of Public Act
799-6, emergency rules to implement the changes made by Article
8II of Public Act 99-6 to the Emergency Telephone System Act may
9be adopted in accordance with this subsection (t) by the
10Department of State Police. The rulemaking authority granted in
11this subsection (t) shall apply only to those rules adopted
12prior to July 1, 2016. The 24-month limitation on the adoption
13of emergency rules does not apply to rules adopted under this
14subsection (t). The adoption of emergency rules authorized by
15this subsection (t) is deemed to be necessary for the public
16interest, safety, and welfare.
17    (u) In order to provide for the expeditious and timely
18implementation of the provisions of the Burn Victims Relief
19Act, emergency rules to implement any provision of the Act may
20be adopted in accordance with this subsection (u) by the
21Department of Insurance. The rulemaking authority granted in
22this subsection (u) shall apply only to those rules adopted
23prior to December 31, 2015. The adoption of emergency rules
24authorized by this subsection (u) is deemed to be necessary for
25the public interest, safety, and welfare.
26    (v) In order to provide for the expeditious and timely

 

 

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1implementation of the provisions of Public Act 99-516,
2emergency rules to implement Public Act 99-516 may be adopted
3in accordance with this subsection (v) by the Department of
4Healthcare and Family Services. The 24-month limitation on the
5adoption of emergency rules does not apply to rules adopted
6under this subsection (v). The adoption of emergency rules
7authorized by this subsection (v) is deemed to be necessary for
8the public interest, safety, and welfare.
9    (w) In order to provide for the expeditious and timely
10implementation of the provisions of Public Act 99-796,
11emergency rules to implement the changes made by Public Act
1299-796 may be adopted in accordance with this subsection (w) by
13the Adjutant General. The adoption of emergency rules
14authorized by this subsection (w) is deemed to be necessary for
15the public interest, safety, and welfare.
16    (x) In order to provide for the expeditious and timely
17implementation of the provisions of Public Act 99-906,
18emergency rules to implement subsection (i) of Section 16-115D,
19subsection (g) of Section 16-128A, and subsection (a) of
20Section 16-128B of the Public Utilities Act may be adopted in
21accordance with this subsection (x) by the Illinois Commerce
22Commission. The rulemaking authority granted in this
23subsection (x) shall apply only to those rules adopted within
24180 days after June 1, 2017 (the effective date of Public Act
2599-906). The adoption of emergency rules authorized by this
26subsection (x) is deemed to be necessary for the public

 

 

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1interest, safety, and welfare.
2    (y) In order to provide for the expeditious and timely
3implementation of the provisions of Public Act 100-23,
4emergency rules to implement the changes made by Public Act
5100-23 to Section 4.02 of the Illinois Act on the Aging,
6Sections 5.5.4 and 5-5.4i of the Illinois Public Aid Code,
7Section 55-30 of the Alcoholism and Other Drug Abuse and
8Dependency Act, and Sections 74 and 75 of the Mental Health and
9Developmental Disabilities Administrative Act may be adopted
10in accordance with this subsection (y) by the respective
11Department. The adoption of emergency rules authorized by this
12subsection (y) is deemed to be necessary for the public
13interest, safety, and welfare.
14    (z) In order to provide for the expeditious and timely
15implementation of the provisions of Public Act 100-554,
16emergency rules to implement the changes made by Public Act
17100-554 to Section 4.7 of the Lobbyist Registration Act may be
18adopted in accordance with this subsection (z) by the Secretary
19of State. The adoption of emergency rules authorized by this
20subsection (z) is deemed to be necessary for the public
21interest, safety, and welfare.
22    (aa) In order to provide for the expeditious and timely
23initial implementation of the changes made to Articles 5, 5A,
2412, and 14 of the Illinois Public Aid Code under the provisions
25of Public Act 100-581, the Department of Healthcare and Family
26Services may adopt emergency rules in accordance with this

 

 

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1subsection (aa). The 24-month limitation on the adoption of
2emergency rules does not apply to rules to initially implement
3the changes made to Articles 5, 5A, 12, and 14 of the Illinois
4Public Aid Code adopted under this subsection (aa). The
5adoption of emergency rules authorized by this subsection (aa)
6is deemed to be necessary for the public interest, safety, and
7welfare.
8    (bb) In order to provide for the expeditious and timely
9implementation of the provisions of Public Act 100-587,
10emergency rules to implement the changes made by Public Act
11100-587 to Section 4.02 of the Illinois Act on the Aging,
12Sections 5.5.4 and 5-5.4i of the Illinois Public Aid Code,
13subsection (b) of Section 55-30 of the Alcoholism and Other
14Drug Abuse and Dependency Act, Section 5-104 of the Specialized
15Mental Health Rehabilitation Act of 2013, and Section 75 and
16subsection (b) of Section 74 of the Mental Health and
17Developmental Disabilities Administrative Act may be adopted
18in accordance with this subsection (bb) by the respective
19Department. The adoption of emergency rules authorized by this
20subsection (bb) is deemed to be necessary for the public
21interest, safety, and welfare.
22    (cc) In order to provide for the expeditious and timely
23implementation of the provisions of Public Act 100-587,
24emergency rules may be adopted in accordance with this
25subsection (cc) to implement the changes made by Public Act
26100-587 to: Sections 14-147.5 and 14-147.6 of the Illinois

 

 

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1Pension Code by the Board created under Article 14 of the Code;
2Sections 15-185.5 and 15-185.6 of the Illinois Pension Code by
3the Board created under Article 15 of the Code; and Sections
416-190.5 and 16-190.6 of the Illinois Pension Code by the Board
5created under Article 16 of the Code. The adoption of emergency
6rules authorized by this subsection (cc) is deemed to be
7necessary for the public interest, safety, and welfare.
8    (dd) In order to provide for the expeditious and timely
9implementation of the provisions of Public Act 100-864,
10emergency rules to implement the changes made by Public Act
11100-864 to Section 3.35 of the Newborn Metabolic Screening Act
12may be adopted in accordance with this subsection (dd) by the
13Secretary of State. The adoption of emergency rules authorized
14by this subsection (dd) is deemed to be necessary for the
15public interest, safety, and welfare.
16    (ee) In order to provide for the expeditious and timely
17implementation of the provisions of this amendatory Act of the
18100th General Assembly, emergency rules implementing the
19Illinois Underground Natural Gas Storage Safety Act may be
20adopted in accordance with this subsection by the Department of
21Natural Resources. The adoption of emergency rules authorized
22by this subsection is deemed to be necessary for the public
23interest, safety, and welfare.
24    (ff) In order to provide for the expeditious and timely
25implementation of the provisions of this amendatory Act of the
26101st General Assembly, emergency rules to implement the

 

 

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1changes to Section 16-107.5 of the Public Utilities Act may be
2adopted in accordance with this subsection by the Illinois
3Commerce Commission. The adoption of emergency rules
4authorized by this subsection is deemed to be necessary for the
5public interest, safety, and welfare.
6(Source: P.A. 99-2, eff. 3-26-15; 99-6, eff. 1-1-16; 99-143,
7eff. 7-27-15; 99-455, eff. 1-1-16; 99-516, eff. 6-30-16;
899-642, eff. 7-28-16; 99-796, eff. 1-1-17; 99-906, eff. 6-1-17;
9100-23, eff. 7-6-17; 100-554, eff. 11-16-17; 100-581, eff.
103-12-18; 100-587, Article 95, Section 95-5, eff. 6-4-18;
11100-587, Article 110, Section 110-5, eff. 6-4-18; 100-864, eff.
128-14-18; 100-1172, eff. 1-4-19.)
 
13    Section 10. The Illinois Enterprise Zone Act is amended by
14changing Section 5.5 as follows:
 
15    (20 ILCS 655/5.5)   (from Ch. 67 1/2, par. 609.1)
16    Sec. 5.5. High Impact Business.
17    (a) In order to respond to unique opportunities to assist
18in the encouragement, development, growth and expansion of the
19private sector through large scale investment and development
20projects, the Department is authorized to receive and approve
21applications for the designation of "High Impact Businesses" in
22Illinois subject to the following conditions:
23        (1) such applications may be submitted at any time
24    during the year;

 

 

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1        (2) such business is not located, at the time of
2    designation, in an enterprise zone designated pursuant to
3    this Act;
4        (3) the business intends to do one or more of the
5    following:
6            (A) the business intends to make a minimum
7        investment of $12,000,000 which will be placed in
8        service in qualified property and intends to create 500
9        full-time equivalent jobs at a designated location in
10        Illinois or intends to make a minimum investment of
11        $30,000,000 which will be placed in service in
12        qualified property and intends to retain 1,500
13        full-time retained jobs at a designated location in
14        Illinois. The business must certify in writing that the
15        investments would not be placed in service in qualified
16        property and the job creation or job retention would
17        not occur without the tax credits and exemptions set
18        forth in subsection (b) of this Section. The terms
19        "placed in service" and "qualified property" have the
20        same meanings as described in subsection (h) of Section
21        201 of the Illinois Income Tax Act; or
22            (B) the business intends to establish a new
23        electric generating facility at a designated location
24        in Illinois. "New electric generating facility", for
25        purposes of this Section, means a newly-constructed
26        electric generation plant or a newly-constructed

 

 

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1        generation capacity expansion at an existing electric
2        generation plant, including the transmission lines and
3        associated equipment that transfers electricity from
4        points of supply to points of delivery, and for which
5        such new foundation construction commenced not sooner
6        than July 1, 2001. Such facility shall be designed to
7        provide baseload electric generation and shall operate
8        on a continuous basis throughout the year; and (i)
9        shall have an aggregate rated generating capacity of at
10        least 1,000 megawatts for all new units at one site if
11        it uses natural gas as its primary fuel and foundation
12        construction of the facility is commenced on or before
13        December 31, 2004, or shall have an aggregate rated
14        generating capacity of at least 400 megawatts for all
15        new units at one site if it uses coal or gases derived
16        from coal as its primary fuel and shall support the
17        creation of at least 150 new Illinois coal mining jobs,
18        or (ii) shall be funded through a federal Department of
19        Energy grant before December 31, 2010 and shall support
20        the creation of Illinois coal-mining jobs, or (iii)
21        shall use coal gasification or integrated
22        gasification-combined cycle units that generate
23        electricity or chemicals, or both, and shall support
24        the creation of Illinois coal-mining jobs. The
25        business must certify in writing that the investments
26        necessary to establish a new electric generating

 

 

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1        facility would not be placed in service and the job
2        creation in the case of a coal-fueled plant would not
3        occur without the tax credits and exemptions set forth
4        in subsection (b-5) of this Section. The term "placed
5        in service" has the same meaning as described in
6        subsection (h) of Section 201 of the Illinois Income
7        Tax Act; or
8            (B-5) the business intends to establish a new
9        gasification facility at a designated location in
10        Illinois. As used in this Section, "new gasification
11        facility" means a newly constructed coal gasification
12        facility that generates chemical feedstocks or
13        transportation fuels derived from coal (which may
14        include, but are not limited to, methane, methanol, and
15        nitrogen fertilizer), that supports the creation or
16        retention of Illinois coal-mining jobs, and that
17        qualifies for financial assistance from the Department
18        before December 31, 2010. A new gasification facility
19        does not include a pilot project located within
20        Jefferson County or within a county adjacent to
21        Jefferson County for synthetic natural gas from coal;
22        or
23            (C) the business intends to establish production
24        operations at a new coal mine, re-establish production
25        operations at a closed coal mine, or expand production
26        at an existing coal mine at a designated location in

 

 

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1        Illinois not sooner than July 1, 2001; provided that
2        the production operations result in the creation of 150
3        new Illinois coal mining jobs as described in
4        subdivision (a)(3)(B) of this Section, and further
5        provided that the coal extracted from such mine is
6        utilized as the predominant source for a new electric
7        generating facility. The business must certify in
8        writing that the investments necessary to establish a
9        new, expanded, or reopened coal mine would not be
10        placed in service and the job creation would not occur
11        without the tax credits and exemptions set forth in
12        subsection (b-5) of this Section. The term "placed in
13        service" has the same meaning as described in
14        subsection (h) of Section 201 of the Illinois Income
15        Tax Act; or
16            (D) the business intends to construct new
17        transmission facilities or upgrade existing
18        transmission facilities at designated locations in
19        Illinois, for which construction commenced not sooner
20        than July 1, 2001. For the purposes of this Section,
21        "transmission facilities" means transmission lines
22        with a voltage rating of 115 kilovolts or above,
23        including associated equipment, that transfer
24        electricity from points of supply to points of delivery
25        and that transmit a majority of the electricity
26        generated by a new electric generating facility

 

 

HB2966- 21 -LRB101 09482 JRG 54580 b

1        designated as a High Impact Business in accordance with
2        this Section. The business must certify in writing that
3        the investments necessary to construct new
4        transmission facilities or upgrade existing
5        transmission facilities would not be placed in service
6        without the tax credits and exemptions set forth in
7        subsection (b-5) of this Section. The term "placed in
8        service" has the same meaning as described in
9        subsection (h) of Section 201 of the Illinois Income
10        Tax Act; or
11            (E) the business intends to establish a new wind
12        power facility at a designated location in Illinois.
13        For purposes of this Section, "new wind power facility"
14        means a newly constructed electric generation
15        facility, or a newly constructed expansion of an
16        existing electric generation facility, placed in
17        service on or after July 1, 2009, that generates
18        electricity using wind energy devices, 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 wind
22        energy devices. For purposes of this Section, "wind
23        energy device" means any device, with a nameplate
24        capacity of at least 0.5 megawatts, that is used in the
25        process of converting kinetic energy from the wind to
26        generate electricity; or

 

 

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1            (E-5) the business intends to establish a new
2        utility-scale solar facility at a designated location
3        in Illinois. For purposes of this Section, "new
4        utility-scale solar power facility" means a newly
5        constructed electric generation facility, or a newly
6        constructed expansion of an existing electric
7        generation facility, placed in service on or after July
8        1, 2019, that (i) generates electricity using
9        photovoltaic cells and (ii) has a nameplate capacity
10        that is greater than 2,000 kilowatts, and such facility
11        shall be deemed to include all associated transmission
12        lines, substations, and other equipment related to the
13        generation of electricity from photovoltaic cells; or
14            (F) the business commits to (i) make a minimum
15        investment of $500,000,000, which will be placed in
16        service in a qualified property, (ii) create 125
17        full-time equivalent jobs at a designated location in
18        Illinois, (iii) establish a fertilizer plant at a
19        designated location in Illinois that complies with the
20        set-back standards as described in Table 1: Initial
21        Isolation and Protective Action Distances in the 2012
22        Emergency Response Guidebook published by the United
23        States Department of Transportation, (iv) pay a
24        prevailing wage for employees at that location who are
25        engaged in construction activities, and (v) secure an
26        appropriate level of general liability insurance to

 

 

HB2966- 23 -LRB101 09482 JRG 54580 b

1        protect against catastrophic failure of the fertilizer
2        plant or any of its constituent systems; in addition,
3        the business must agree to enter into a construction
4        project labor agreement including provisions
5        establishing wages, benefits, and other compensation
6        for employees performing work under the project labor
7        agreement at that location; for the purposes of this
8        Section, "fertilizer plant" means a newly constructed
9        or upgraded plant utilizing gas used in the production
10        of anhydrous ammonia and downstream nitrogen
11        fertilizer products for resale; for the purposes of
12        this Section, "prevailing wage" means the hourly cash
13        wages plus fringe benefits for training and
14        apprenticeship programs approved by the U.S.
15        Department of Labor, Bureau of Apprenticeship and
16        Training, health and welfare, insurance, vacations and
17        pensions paid generally, in the locality in which the
18        work is being performed, to employees engaged in work
19        of a similar character on public works; this paragraph
20        (F) applies only to businesses that submit an
21        application to the Department within 60 days after the
22        effective date of this amendatory Act of the 98th
23        General Assembly; and
24        (4) no later than 90 days after an application is
25    submitted, the Department shall notify the applicant of the
26    Department's determination of the qualification of the

 

 

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1    proposed High Impact Business under this Section.
2    (b) Businesses designated as High Impact Businesses
3pursuant to subdivision (a)(3)(A) of this Section shall qualify
4for the credits and exemptions described in the following Acts:
5Section 9-222 and Section 9-222.1A of the Public Utilities Act,
6subsection (h) of Section 201 of the Illinois Income Tax Act,
7and Section 1d of the Retailers' Occupation Tax Act; provided
8that these credits and exemptions described in these Acts shall
9not be authorized until the minimum investments set forth in
10subdivision (a)(3)(A) of this Section have been placed in
11service in qualified properties and, in the case of the
12exemptions described in the Public Utilities Act and Section 1d
13of the Retailers' Occupation Tax Act, the minimum full-time
14equivalent jobs or full-time retained jobs set forth in
15subdivision (a)(3)(A) of this Section have been created or
16retained. Businesses designated as High Impact Businesses
17under this Section shall also qualify for the exemption
18described in Section 5l of the Retailers' Occupation Tax Act.
19The credit provided in subsection (h) of Section 201 of the
20Illinois Income Tax Act shall be applicable to investments in
21qualified property as set forth in subdivision (a)(3)(A) of
22this Section.
23    (b-5) Businesses designated as High Impact Businesses
24pursuant to subdivisions (a)(3)(B), (a)(3)(B-5), (a)(3)(C),
25and (a)(3)(D) of this Section shall qualify for the credits and
26exemptions described in the following Acts: Section 51 of the

 

 

HB2966- 25 -LRB101 09482 JRG 54580 b

1Retailers' Occupation Tax Act, Section 9-222 and Section
29-222.1A of the Public Utilities Act, and subsection (h) of
3Section 201 of the Illinois Income Tax Act; however, the
4credits and exemptions authorized under Section 9-222 and
5Section 9-222.1A of the Public Utilities Act, and subsection
6(h) of Section 201 of the Illinois Income Tax Act shall not be
7authorized until the new electric generating facility, the new
8gasification facility, the new transmission facility, or the
9new, expanded, or reopened coal mine is operational, except
10that a new electric generating facility whose primary fuel
11source is natural gas is eligible only for the exemption under
12Section 5l of the Retailers' Occupation Tax Act.
13    (b-6) Businesses designated as High Impact Businesses
14pursuant to subdivision (a)(3)(E) of this Section shall qualify
15for the exemptions described in Section 5l of the Retailers'
16Occupation Tax Act; any business so designated as a High Impact
17Business being, for purposes of this Section, a "Wind Energy
18Business".
19    (c) High Impact Businesses located in federally designated
20foreign trade zones or sub-zones are also eligible for
21additional credits, exemptions and deductions as described in
22the following Acts: Section 9-221 and Section 9-222.1 of the
23Public Utilities Act; and subsection (g) of Section 201, and
24Section 203 of the Illinois Income Tax Act.
25    (d) Except for businesses contemplated under subdivision
26(a)(3)(E) of this Section, existing Illinois businesses which

 

 

HB2966- 26 -LRB101 09482 JRG 54580 b

1apply for designation as a High Impact Business must provide
2the Department with the prospective plan for which 1,500
3full-time retained jobs would be eliminated in the event that
4the business is not designated.
5    (e) Except for new wind power facilities contemplated under
6subdivision (a)(3)(E) of this Section, new proposed facilities
7which apply for designation as High Impact Business must
8provide the Department with proof of alternative non-Illinois
9sites which would receive the proposed investment and job
10creation in the event that the business is not designated as a
11High Impact Business.
12    (f) Except for businesses contemplated under subdivision
13(a)(3)(E) of this Section, in the event that a business is
14designated a High Impact Business and it is later determined
15after reasonable notice and an opportunity for a hearing as
16provided under the Illinois Administrative Procedure Act, that
17the business would have placed in service in qualified property
18the investments and created or retained the requisite number of
19jobs without the benefits of the High Impact Business
20designation, the Department shall be required to immediately
21revoke the designation and notify the Director of the
22Department of Revenue who shall begin proceedings to recover
23all wrongfully exempted State taxes with interest. The business
24shall also be ineligible for all State funded Department
25programs for a period of 10 years.
26    (g) The Department shall revoke a High Impact Business

 

 

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1designation if the participating business fails to comply with
2the terms and conditions of the designation. However, the
3penalties for new wind power facilities or Wind Energy
4Businesses or new utility-scale solar power facility for
5failure to comply with any of the terms or conditions of the
6Illinois Prevailing Wage Act shall be only those penalties
7identified in the Illinois Prevailing Wage Act, and the
8Department shall not revoke a High Impact Business designation
9as a result of the failure to comply with any of the terms or
10conditions of the Illinois Prevailing Wage Act in relation to a
11new wind power facility or a Wind Energy Business or new
12utility-scale solar power facility.
13    (h) Prior to designating a business, the Department shall
14provide the members of the General Assembly and Commission on
15Government Forecasting and Accountability with a report
16setting forth the terms and conditions of the designation and
17guarantees that have been received by the Department in
18relation to the proposed business being designated.
19(Source: P.A. 97-905, eff. 8-7-12; 98-109, eff. 7-25-13.)
 
20    Section 15. The Illinois Power Agency Act is amended by
21changing Sections 1-10, 1-56, and 1-75 as follows:
 
22    (20 ILCS 3855/1-10)
23    Sec. 1-10. Definitions.
24    "Agency" means the Illinois Power Agency.

 

 

HB2966- 28 -LRB101 09482 JRG 54580 b

1    "Agency loan agreement" means any agreement pursuant to
2which the Illinois Finance Authority agrees to loan the
3proceeds of revenue bonds issued with respect to a project to
4the Agency upon terms providing for loan repayment installments
5at least sufficient to pay when due all principal of, interest
6and premium, if any, on those revenue bonds, and providing for
7maintenance, insurance, and other matters in respect of the
8project.
9    "Authority" means the Illinois Finance Authority.
10    "Brownfield site photovoltaic project" means photovoltaics
11that are:
12        (1) interconnected to an electric utility as defined in
13    this Section, a municipal utility as defined in this
14    Section, a public utility as defined in Section 3-105 of
15    the Public Utilities Act, or an electric cooperative, as
16    defined in Section 3-119 of the Public Utilities Act; and
17        (2) located at a site that is regulated by any of the
18    following entities under the following programs:
19            (A) the United States Environmental Protection
20        Agency under the federal Comprehensive Environmental
21        Response, Compensation, and Liability Act of 1980, as
22        amended;
23            (B) the United States Environmental Protection
24        Agency under the Corrective Action Program of the
25        federal Resource Conservation and Recovery Act, as
26        amended;

 

 

HB2966- 29 -LRB101 09482 JRG 54580 b

1            (C) the Illinois Environmental Protection Agency
2        under the Illinois Site Remediation Program; or
3            (D) the Illinois Environmental Protection Agency
4        under the Illinois Solid Waste Program.
5    "Clean coal facility" means an electric generating
6facility that uses primarily coal as a feedstock and that
7captures and sequesters carbon dioxide emissions at the
8following levels: at least 50% of the total carbon dioxide
9emissions that the facility would otherwise emit if, at the
10time construction commences, the facility is scheduled to
11commence operation before 2016, at least 70% of the total
12carbon dioxide emissions that the facility would otherwise emit
13if, at the time construction commences, the facility is
14scheduled to commence operation during 2016 or 2017, and at
15least 90% of the total carbon dioxide emissions that the
16facility would otherwise emit if, at the time construction
17commences, the facility is scheduled to commence operation
18after 2017. The power block of the clean coal facility shall
19not exceed allowable emission rates for sulfur dioxide,
20nitrogen oxides, carbon monoxide, particulates and mercury for
21a natural gas-fired combined-cycle facility the same size as
22and in the same location as the clean coal facility at the time
23the clean coal facility obtains an approved air permit. All
24coal used by a clean coal facility shall have high volatile
25bituminous rank and greater than 1.7 pounds of sulfur per
26million btu content, unless the clean coal facility does not

 

 

HB2966- 30 -LRB101 09482 JRG 54580 b

1use gasification technology and was operating as a conventional
2coal-fired electric generating facility on June 1, 2009 (the
3effective date of Public Act 95-1027).
4    "Clean coal SNG brownfield facility" means a facility that
5(1) has commenced construction by July 1, 2015 on an urban
6brownfield site in a municipality with at least 1,000,000
7residents; (2) uses a gasification process to produce
8substitute natural gas; (3) uses coal as at least 50% of the
9total feedstock over the term of any sourcing agreement with a
10utility and the remainder of the feedstock may be either
11petroleum coke or coal, with all such coal having a high
12bituminous rank and greater than 1.7 pounds of sulfur per
13million Btu content unless the facility reasonably determines
14that it is necessary to use additional petroleum coke to
15deliver additional consumer savings, in which case the facility
16shall use coal for at least 35% of the total feedstock over the
17term of any sourcing agreement; and (4) captures and sequesters
18at least 85% of the total carbon dioxide emissions that the
19facility would otherwise emit.
20    "Clean coal SNG facility" means a facility that uses a
21gasification process to produce substitute natural gas, that
22sequesters at least 90% of the total carbon dioxide emissions
23that the facility would otherwise emit, that uses at least 90%
24coal as a feedstock, with all such coal having a high
25bituminous rank and greater than 1.7 pounds of sulfur per
26million btu content, and that has a valid and effective permit

 

 

HB2966- 31 -LRB101 09482 JRG 54580 b

1to construct emission sources and air pollution control
2equipment and approval with respect to the federal regulations
3for Prevention of Significant Deterioration of Air Quality
4(PSD) for the plant pursuant to the federal Clean Air Act;
5provided, however, a clean coal SNG brownfield facility shall
6not be a clean coal SNG facility.
7    "Commission" means the Illinois Commerce Commission.
8    "Community renewable generation project" means an electric
9generating facility that:
10        (1) is powered by wind, solar thermal energy,
11    photovoltaic cells or panels, biodiesel, crops and
12    untreated and unadulterated organic waste biomass, tree
13    waste, and hydropower that does not involve new
14    construction or significant expansion of hydropower dams;
15        (2) is interconnected at the distribution system level
16    of an electric utility as defined in this Section, a
17    municipal utility as defined in this Section that owns or
18    operates electric distribution facilities, a public
19    utility as defined in Section 3-105 of the Public Utilities
20    Act, or an electric cooperative, as defined in Section
21    3-119 of the Public Utilities Act;
22        (3) credits the value of electricity generated by the
23    facility to the subscribers of the facility; and
24        (4) is limited in nameplate capacity to less than or
25    equal to 2,000 kilowatts.
26    "Costs incurred in connection with the development and

 

 

HB2966- 32 -LRB101 09482 JRG 54580 b

1construction of a facility" means:
2        (1) the cost of acquisition of all real property,
3    fixtures, and improvements in connection therewith and
4    equipment, personal property, and other property, rights,
5    and easements acquired that are deemed necessary for the
6    operation and maintenance of the facility;
7        (2) financing costs with respect to bonds, notes, and
8    other evidences of indebtedness of the Agency;
9        (3) all origination, commitment, utilization,
10    facility, placement, underwriting, syndication, credit
11    enhancement, and rating agency fees;
12        (4) engineering, design, procurement, consulting,
13    legal, accounting, title insurance, survey, appraisal,
14    escrow, trustee, collateral agency, interest rate hedging,
15    interest rate swap, capitalized interest, contingency, as
16    required by lenders, and other financing costs, and other
17    expenses for professional services; and
18        (5) the costs of plans, specifications, site study and
19    investigation, installation, surveys, other Agency costs
20    and estimates of costs, and other expenses necessary or
21    incidental to determining the feasibility of any project,
22    together with such other expenses as may be necessary or
23    incidental to the financing, insuring, acquisition, and
24    construction of a specific project and starting up,
25    commissioning, and placing that project in operation.
26    "Delivery services" has the same definition as found in

 

 

HB2966- 33 -LRB101 09482 JRG 54580 b

1Section 16-102 of the Public Utilities Act.
2    "Delivery year" means the consecutive 12-month period
3beginning June 1 of a given year and ending May 31 of the
4following year.
5    "Department" means the Department of Commerce and Economic
6Opportunity.
7    "Director" means the Director of the Illinois Power Agency.
8    "Demand-response" means measures that decrease peak
9electricity demand or shift demand from peak to off-peak
10periods.
11    "Distributed renewable energy generation device" means a
12device that is:
13        (1) powered by wind, solar thermal energy,
14    photovoltaic cells or panels, biodiesel, crops and
15    untreated and unadulterated organic waste biomass, tree
16    waste, and hydropower that does not involve new
17    construction or significant expansion of hydropower dams;
18        (2) interconnected at the distribution system level of
19    either an electric utility as defined in this Section, a
20    municipal utility as defined in this Section that owns or
21    operates electric distribution facilities, or a rural
22    electric cooperative as defined in Section 3-119 of the
23    Public Utilities Act;
24        (3) located on the customer side of the customer's
25    electric meter and is primarily used to offset that
26    customer's electricity load; and

 

 

HB2966- 34 -LRB101 09482 JRG 54580 b

1        (4) limited in nameplate capacity to less than or equal
2    to 2,000 kilowatts.
3    "Energy efficiency" means measures that reduce the amount
4of electricity or natural gas consumed in order to achieve a
5given end use. "Energy efficiency" includes voltage
6optimization measures that optimize the voltage at points on
7the electric distribution voltage system and thereby reduce
8electricity consumption by electric customers' end use
9devices. "Energy efficiency" also includes measures that
10reduce the total Btus of electricity, natural gas, and other
11fuels needed to meet the end use or uses.
12    "Electric utility" has the same definition as found in
13Section 16-102 of the Public Utilities Act.
14    "Facility" means an electric generating unit or a
15co-generating unit that produces electricity along with
16related equipment necessary to connect the facility to an
17electric transmission or distribution system.
18    "Governmental aggregator" means one or more units of local
19government that individually or collectively procure
20electricity to serve residential retail electrical loads
21located within its or their jurisdiction.
22    "Index price" means the monthly average load-weighted
23day-ahead price at the ComEd or Ameren Hub.
24    "Local government" means a unit of local government as
25defined in Section 1 of Article VII of the Illinois
26Constitution.

 

 

HB2966- 35 -LRB101 09482 JRG 54580 b

1    "Municipality" means a city, village, or incorporated
2town.
3    "Municipal utility" means a public utility owned and
4operated by any subdivision or municipal corporation of this
5State.
6    "Nameplate capacity" means the aggregate inverter
7nameplate capacity in kilowatts AC.
8    "Offer strike price" means the price for a renewable energy
9credit from a new utility-scale wind project or a utility-scale
10solar project resulting from a new utility-scale wind or solar
11competitive procurement.
12    "Person" means any natural person, firm, partnership,
13corporation, either domestic or foreign, company, association,
14limited liability company, joint stock company, or association
15and includes any trustee, receiver, assignee, or personal
16representative thereof.
17    "Project" means the planning, bidding, and construction of
18a facility.
19    "Public utility" has the same definition as found in
20Section 3-105 of the Public Utilities Act.
21    "Real property" means any interest in land together with
22all structures, fixtures, and improvements thereon, including
23lands under water and riparian rights, any easements,
24covenants, licenses, leases, rights-of-way, uses, and other
25interests, together with any liens, judgments, mortgages, or
26other claims or security interests related to real property.

 

 

HB2966- 36 -LRB101 09482 JRG 54580 b

1    "Renewable energy credit" means a tradable credit that
2represents the environmental attributes of one megawatt hour of
3energy produced from a renewable energy resource.
4    "Renewable energy resources" includes energy and its
5associated renewable energy credit or renewable energy credits
6from wind, solar thermal energy, photovoltaic cells and panels,
7biodiesel, anaerobic digestion, crops and untreated and
8unadulterated organic waste biomass, tree waste, and
9hydropower that does not involve new construction or
10significant expansion of hydropower dams. For purposes of this
11Act, landfill gas produced in the State is considered a
12renewable energy resource. "Renewable energy resources" does
13not include the incineration or burning of tires, garbage,
14general household, institutional, and commercial waste,
15industrial lunchroom or office waste, landscape waste other
16than tree waste, railroad crossties, utility poles, or
17construction or demolition debris, other than untreated and
18unadulterated waste wood.
19    "Retail customer" has the same definition as found in
20Section 16-102 of the Public Utilities Act.
21    "Revenue bond" means any bond, note, or other evidence of
22indebtedness issued by the Authority, the principal and
23interest of which is payable solely from revenues or income
24derived from any project or activity of the Agency.
25    "Sequester" means permanent storage of carbon dioxide by
26injecting it into a saline aquifer, a depleted gas reservoir,

 

 

HB2966- 37 -LRB101 09482 JRG 54580 b

1or an oil reservoir, directly or through an enhanced oil
2recovery process that may involve intermediate storage,
3regardless of whether these activities are conducted by a clean
4coal facility, a clean coal SNG facility, a clean coal SNG
5brownfield facility, or a party with which a clean coal
6facility, clean coal SNG facility, or clean coal SNG brownfield
7facility has contracted for such purposes.
8    "Service area" has the same definition as found in Section
916-102 of the Public Utilities Act.
10    "Sourcing agreement" means (i) in the case of an electric
11utility, an agreement between the owner of a clean coal
12facility and such electric utility, which agreement shall have
13terms and conditions meeting the requirements of paragraph (3)
14of subsection (d) of Section 1-75, (ii) in the case of an
15alternative retail electric supplier, an agreement between the
16owner of a clean coal facility and such alternative retail
17electric supplier, which agreement shall have terms and
18conditions meeting the requirements of Section 16-115(d)(5) of
19the Public Utilities Act, and (iii) in case of a gas utility,
20an agreement between the owner of a clean coal SNG brownfield
21facility and the gas utility, which agreement shall have the
22terms and conditions meeting the requirements of subsection
23(h-1) of Section 9-220 of the Public Utilities Act.
24    "Subscriber" means a person who (i) takes delivery service
25from an electric utility, and (ii) has a subscription of no
26less than 200 watts to a community renewable generation project

 

 

HB2966- 38 -LRB101 09482 JRG 54580 b

1that is located in the electric utility's service area. No
2subscriber's subscriptions may total more than 40% of the
3nameplate capacity of an individual community renewable
4generation project. Entities that are affiliated by virtue of a
5common parent shall not represent multiple subscriptions that
6total more than 40% of the nameplate capacity of an individual
7community renewable generation project.
8    "Subscription" means an interest in a community renewable
9generation project expressed in kilowatts, which is sized
10primarily to offset part or all of the subscriber's electricity
11usage.
12    "Substitute natural gas" or "SNG" means a gas manufactured
13by gasification of hydrocarbon feedstock, which is
14substantially interchangeable in use and distribution with
15conventional natural gas.
16    "Total resource cost test" or "TRC test" means a standard
17that is met if, for an investment in energy efficiency or
18demand-response measures, the benefit-cost ratio is greater
19than one. The benefit-cost ratio is the ratio of the net
20present value of the total benefits of the program to the net
21present value of the total costs as calculated over the
22lifetime of the measures. A total resource cost test compares
23the sum of avoided electric utility costs, representing the
24benefits that accrue to the system and the participant in the
25delivery of those efficiency measures and including avoided
26costs associated with reduced use of natural gas or other

 

 

HB2966- 39 -LRB101 09482 JRG 54580 b

1fuels, avoided costs associated with reduced water
2consumption, and avoided costs associated with reduced
3operation and maintenance costs, as well as other quantifiable
4societal benefits, to the sum of all incremental costs of
5end-use measures that are implemented due to the program
6(including both utility and participant contributions), plus
7costs to administer, deliver, and evaluate each demand-side
8program, to quantify the net savings obtained by substituting
9the demand-side program for supply resources. In calculating
10avoided costs of power and energy that an electric utility
11would otherwise have had to acquire, reasonable estimates shall
12be included of financial costs likely to be imposed by future
13regulations and legislation on emissions of greenhouse gases.
14In discounting future societal costs and benefits for the
15purpose of calculating net present values, a societal discount
16rate based on actual, long-term Treasury bond yields should be
17used. Notwithstanding anything to the contrary, the TRC test
18shall not include or take into account a calculation of market
19price suppression effects or demand reduction induced price
20effects.
21    "Utility-scale solar project" means an electric generating
22facility that:
23        (1) generates electricity using photovoltaic cells;
24    and
25        (2) has a nameplate capacity that is greater than 2,000
26    kilowatts.

 

 

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1    "Utility-scale wind project" means an electric generating
2facility that:
3        (1) generates electricity using wind; and
4        (2) has a nameplate capacity that is greater than 2,000
5    kilowatts.
6    "Variable renewable energy credit" means a renewable
7energy credit which is the difference between the offer strike
8price and the index price.
9    "Zero emission credit" means a tradable credit that
10represents the environmental attributes of one megawatt hour of
11energy produced from a zero emission facility.
12    "Zero emission facility" means a facility that: (1) is
13fueled by nuclear power; and (2) is interconnected with PJM
14Interconnection, LLC or the Midcontinent Independent System
15Operator, Inc., or their successors.
16(Source: P.A. 98-90, eff. 7-15-13; 99-906, eff. 6-1-17.)
 
17    (20 ILCS 3855/1-56)
18    Sec. 1-56. Illinois Power Agency Renewable Energy
19Resources Fund; Illinois Solar for All Program.
20    (a) The Illinois Power Agency Renewable Energy Resources
21Fund is created as a special fund in the State treasury.
22    (b) The Illinois Power Agency Renewable Energy Resources
23Fund shall be administered by the Agency as described in this
24subsection (b), provided that the changes to this subsection
25(b) made by this amendatory Act of the 99th General Assembly

 

 

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1shall not interfere with existing contracts under this Section.
2        (1) The Illinois Power Agency Renewable Energy
3    Resources Fund shall be used to purchase renewable energy
4    credits according to any approved procurement plan
5    developed by the Agency prior to June 1, 2017.
6        (2) The Illinois Power Agency Renewable Energy
7    Resources Fund shall also be used to create the Illinois
8    Solar for All Program, which shall include incentives for
9    low-income distributed generation and community solar
10    projects, and other associated approved expenditures. The
11    objectives of the Illinois Solar for All Program are to
12    bring photovoltaics to low-income communities in this
13    State in a manner that maximizes the development of new
14    photovoltaic generating facilities, to create a long-term,
15    low-income solar marketplace throughout this State, to
16    integrate, through interaction with stakeholders, with
17    existing energy efficiency initiatives, and to minimize
18    administrative costs. The Agency shall include a
19    description of its proposed approach to the design,
20    administration, implementation and evaluation of the
21    Illinois Solar for All Program, as part of the long-term
22    renewable resources procurement plan authorized by
23    subsection (c) of Section 1-75 of this Act, and the program
24    shall be designed to grow the low-income solar market. The
25    Agency or utility, as applicable, shall purchase renewable
26    energy credits from the (i) photovoltaic distributed

 

 

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1    renewable energy generation projects and (ii) community
2    solar projects that are procured under procurement
3    processes authorized by the long-term renewable resources
4    procurement plans approved by the Commission.
5        The Illinois Solar for All Program shall include the
6    program offerings described in subparagraphs (A) through
7    (D) of this paragraph (2), which the Agency shall implement
8    through contracts with third-party providers and, subject
9    to appropriation, pay the approximate amounts identified
10    using monies available in the Illinois Power Agency
11    Renewable Energy Resources Fund. Each contract that
12    provides for the installation of solar facilities shall
13    provide that the solar facilities will produce energy and
14    economic benefits, at a level determined by the Agency to
15    be reasonable, for the participating low income customers.
16    The monies available in the Illinois Power Agency Renewable
17    Energy Resources Fund and not otherwise committed to
18    contracts executed under subsection (i) of this Section
19    shall be allocated among the programs described in this
20    paragraph (2), as follows: 22.5% of these funds shall be
21    allocated to programs described in subparagraph (A) of this
22    paragraph (2), 37.5% of these funds shall be allocated to
23    programs described in subparagraph (B) of this paragraph
24    (2), 15% of these funds shall be allocated to programs
25    described in subparagraph (C) of this paragraph (2), and
26    25% of these funds, but in no event more than $50,000,000,

 

 

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1    shall be allocated to programs described in subparagraph
2    (D) of this paragraph (2). The allocation of funds among
3    subparagraphs (A), (B), or (C) of this paragraph (2) may be
4    changed if the Agency or administrator, through delegated
5    authority, determines incentives in subparagraphs (A),
6    (B), or (C) of this paragraph (2) have not been adequately
7    subscribed to fully utilize the Illinois Power Agency
8    Renewable Energy Resources Fund. The determination shall
9    include input through a stakeholder process. The program
10    offerings described in subparagraphs (A) through (D) of
11    this paragraph (2) shall also be implemented through
12    contracts funded from such additional amounts as are
13    allocated to one or more of the programs in the long-term
14    renewable resources procurement plans as specified in
15    subsection (c) of Section 1-75 of this Act and subparagraph
16    (O) of paragraph (1) of such subsection (c).
17        Contracts that will be paid with funds in the Illinois
18    Power Agency Renewable Energy Resources Fund shall be
19    executed by the Agency. Contracts that will be paid with
20    funds collected by an electric utility shall be executed by
21    the electric utility.
22        Contracts under the Illinois Solar for All Program
23    shall include an approach, as set forth in the long-term
24    renewable resources procurement plans, to ensure the
25    wholesale market value of the energy is credited to
26    participating low-income customers or organizations and to

 

 

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1    ensure tangible economic benefits flow directly to program
2    participants, except in the case of low-income
3    multi-family housing where the low-income customer does
4    not directly pay for energy. Priority shall be given to
5    projects that demonstrate meaningful involvement of
6    low-income community members in designing the initial
7    proposals. Acceptable proposals to implement projects must
8    demonstrate the applicant's ability to conduct initial
9    community outreach, education, and recruitment of
10    low-income participants in the community. Projects must
11    include job training opportunities if available, and shall
12    endeavor to coordinate with the job training programs
13    described in paragraph (1) of subsection (a) of Section
14    16-108.12 of the Public Utilities Act.
15            (A) Low-income distributed generation incentive.
16        This program will provide incentives to low-income
17        customers, either directly or through solar providers,
18        to increase the participation of low-income households
19        in photovoltaic on-site distributed generation.
20        Companies participating in this program that install
21        solar panels shall commit to hiring job trainees for a
22        portion of their low-income installations, and an
23        administrator shall facilitate partnering the
24        companies that install solar panels with entities that
25        provide solar panel installation job training. It is a
26        goal of this program that a minimum of 25% of the

 

 

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

 

 

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1        Contracts entered into under this paragraph may be
2        entered into with developers and shall also include
3        contracts for renewable energy credits related to the
4        program.
5            (C) Incentives for non-profits and public
6        facilities. Under this program funds shall be used to
7        support on-site photovoltaic distributed renewable
8        energy generation devices to serve the load associated
9        with not-for-profit customers and to support
10        photovoltaic distributed renewable energy generation
11        that uses photovoltaic technology to serve the load
12        associated with public sector customers taking service
13        at public buildings. It is a goal of this program that
14        at least 25% of the incentives for this program be
15        allocated to projects located in environmental justice
16        communities. Contracts entered into under this
17        paragraph may be entered into with an entity that will
18        develop and administer the program or with developers
19        and shall also include contracts for renewable energy
20        credits related to the program.
21            (D) Low-Income Community Solar Pilot Projects.
22        Under this program, persons, including, but not
23        limited to, electric utilities, shall propose pilot
24        community solar projects. Community solar projects
25        proposed under this subparagraph (D) may exceed 2,000
26        kilowatts in nameplate capacity, but the amount paid

 

 

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1        per project under this program may not exceed
2        $20,000,000. Pilot projects must result in economic
3        benefits for the members of the community in which the
4        project will be located. The proposed pilot project
5        must include a partnership with at least one
6        community-based organization. Approved pilot projects
7        shall be competitively bid by the Agency, subject to
8        fair and equitable guidelines developed by the Agency.
9        Funding available under this subparagraph (D) may not
10        be distributed solely to a utility, and at least some
11        funds under this subparagraph (D) must include a
12        project partnership that includes community ownership
13        by the project subscribers. Contracts entered into
14        under this paragraph may be entered into with an entity
15        that will develop and administer the program or with
16        developers and shall also include contracts for
17        renewable energy credits related to the program. A
18        project proposed by a utility that is implemented under
19        this subparagraph (D) shall not be included in the
20        utility's ratebase.
21        The requirement that a qualified person, as defined in
22    paragraph (1) of subsection (i) of this Section, install
23    photovoltaic devices does not apply to the Illinois Solar
24    for All Program described in this subsection (b).
25        (3) Costs associated with the Illinois Solar for All
26    Program and its components described in paragraph (2) of

 

 

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1    this subsection (b), including, but not limited to, costs
2    associated with procuring experts, consultants, and the
3    program administrator referenced in this subsection (b)
4    and related incremental costs, and costs related to the
5    evaluation of the Illinois Solar for All Program, may be
6    paid for using monies in the Illinois Power Agency
7    Renewable Energy Resources Fund, but the Agency or program
8    administrator shall strive to minimize costs in the
9    implementation of the program. The Agency shall purchase
10    renewable energy credits from generation that is the
11    subject of a contract under subparagraphs (A) through (D)
12    of this paragraph (2) of this subsection (b), and may pay
13    for such renewable energy credits through an upfront
14    payment per installed kilowatt of nameplate capacity paid
15    once the device is interconnected at the distribution
16    system level of the utility and is energized. The payment
17    shall be in exchange for an assignment of all renewable
18    energy credits generated by the system during the first 15
19    years of operation and shall be structured to overcome
20    barriers to participation in the solar market by the
21    low-income community. The incentives provided for in this
22    Section may be implemented through the pricing of renewable
23    energy credits where the prices paid for the credits are
24    higher than the prices from programs offered under
25    subsection (c) of Section 1-75 of this Act to account for
26    the incentives. If the prices paid for renewable energy

 

 

HB2966- 49 -LRB101 09482 JRG 54580 b

1    credits under this Section are higher than the prices paid
2    from programs offered under subsection (c) of Section 1-75
3    of this Act, then the average difference in price for a
4    comparable product shall not count toward the limitation or
5    reduction found in subparagraph (E) of paragraph (1) of
6    subsection (c) of Section 1-75 of this Act. The Agency
7    shall ensure collaboration with community agencies, and
8    allocate up to 5% of the funds available under the Illinois
9    Solar for All Program to community-based groups to assist
10    in grassroots education efforts related to the Illinois
11    Solar for All Program. The Agency shall retire any
12    renewable energy credits purchased from this program and
13    the credits shall count towards the obligation under
14    subsection (c) of Section 1-75 of this Act for the electric
15    utility to which the project is interconnected.
16        (4) The Agency shall, consistent with the requirements
17    of this subsection (b), propose the Illinois Solar for All
18    Program terms, conditions, and requirements, including the
19    prices to be paid for renewable energy credits, and which
20    prices may be determined through a formula, through the
21    development, review, and approval of the Agency's
22    long-term renewable resources procurement plan described
23    in subsection (c) of Section 1-75 of this Act and Section
24    16-111.5 of the Public Utilities Act. In the course of the
25    Commission proceeding initiated to review and approve the
26    plan, including the Illinois Solar for All Program proposed

 

 

HB2966- 50 -LRB101 09482 JRG 54580 b

1    by the Agency, a party may propose an additional low-income
2    solar or solar incentive program, or modifications to the
3    programs proposed by the Agency, and the Commission may
4    approve an additional program, or modifications to the
5    Agency's proposed program, if the additional or modified
6    program more effectively maximizes the benefits to
7    low-income customers after taking into account all
8    relevant factors, including, but not limited to, the extent
9    to which a competitive market for low-income solar has
10    developed. Following the Commission's approval of the
11    Illinois Solar for All Program, the Agency or a party may
12    propose adjustments to the program terms, conditions, and
13    requirements, including the price offered to new systems,
14    to ensure the long-term viability and success of the
15    program. The Commission shall review and approve any
16    modifications to the program through the plan revision
17    process described in Section 16-111.5 of the Public
18    Utilities Act.
19        (5) The Agency shall issue a request for qualifications
20    for a third-party program administrator or administrators
21    to administer all or a portion of the Illinois Solar for
22    All Program. The third-party program administrator shall
23    be chosen through a competitive bid process based on
24    selection criteria and requirements developed by the
25    Agency, including, but not limited to, experience in
26    administering low-income energy programs and overseeing

 

 

HB2966- 51 -LRB101 09482 JRG 54580 b

1    statewide clean energy or energy efficiency services. If
2    the Agency retains a program administrator or
3    administrators to implement all or a portion of the
4    Illinois Solar for All Program, each administrator shall
5    periodically submit reports to the Agency and Commission
6    for each program that it administers, at appropriate
7    intervals to be identified by the Agency in its long-term
8    renewable resources procurement plan, provided that the
9    reporting interval is at least quarterly.
10        (6) The long-term renewable resources procurement plan
11    shall also provide for an independent evaluation of the
12    Illinois Solar for All Program. At least every 2 years, the
13    Agency shall select an independent evaluator to review and
14    report on the Illinois Solar for All Program and the
15    performance of the third-party program administrator of
16    the Illinois Solar for All Program. The evaluation shall be
17    based on objective criteria developed through a public
18    stakeholder process. The process shall include feedback
19    and participation from Illinois Solar for All Program
20    stakeholders, including participants and organizations in
21    environmental justice and historically underserved
22    communities. The report shall include a summary of the
23    evaluation of the Illinois Solar for All Program based on
24    the stakeholder developed objective criteria. The report
25    shall include the number of projects installed; the total
26    installed capacity in kilowatts; the average cost per

 

 

HB2966- 52 -LRB101 09482 JRG 54580 b

1    kilowatt of installed capacity to the extent reasonably
2    obtainable by the Agency; the number of jobs or job
3    opportunities created; economic, social, and environmental
4    benefits created; and the total administrative costs
5    expended by the Agency and program administrator to
6    implement and evaluate the program. The report shall be
7    delivered to the Commission and posted on the Agency's
8    website, and shall be used, as needed, to revise the
9    Illinois Solar for All Program. The Commission shall also
10    consider the results of the evaluation as part of its
11    review of the long-term renewable resources procurement
12    plan under subsection (c) of Section 1-75 of this Act.
13        (7) If additional funding for the programs described in
14    this subsection (b) is available under subsection (k) of
15    Section 16-108 of the Public Utilities Act, then the Agency
16    shall submit a procurement plan to the Commission no later
17    than September 1, 2018, that proposes how the Agency will
18    procure programs on behalf of the applicable utility. After
19    notice and hearing, the Commission shall approve, or
20    approve with modification, the plan no later than November
21    1, 2018.
22    As used in this subsection (b), "low-income households"
23means persons and families whose income does not exceed 80% of
24area median income, adjusted for family size and revised every
255 years.
26    For the purposes of this subsection (b), the Agency shall

 

 

HB2966- 53 -LRB101 09482 JRG 54580 b

1define "environmental justice community" as part of long-term
2renewable resources procurement plan development, to ensure,
3to the extent practicable, compatibility with other agencies'
4definitions and may, for guidance, look to the definitions used
5by federal, state, or local governments.
6    (b-5) After the receipt of all payments required by Section
716-115D of the Public Utilities Act, no additional funds shall
8be deposited into the Illinois Power Agency Renewable Energy
9Resources Fund unless directed by order of the Commission.
10    (b-10) After the receipt of all payments required by
11Section 16-115D of the Public Utilities Act and payment in full
12of all contracts executed by the Agency under subsections (b)
13and (i) of this Section, if the balance of the Illinois Power
14Agency Renewable Energy Resources Fund is under $5,000, then
15the Fund shall be inoperative and any remaining funds and any
16funds submitted to the Fund after that date, shall be
17transferred to the Supplemental Low-Income Energy Assistance
18Fund for use in the Low-Income Home Energy Assistance Program,
19as authorized by the Energy Assistance Act.
20    (c) (Blank).
21    (d) (Blank).
22    (e) All renewable energy credits procured using monies from
23the Illinois Power Agency Renewable Energy Resources Fund shall
24be permanently retired.
25    (f) The selection of one or more third-party program
26managers or administrators, the selection of the independent

 

 

HB2966- 54 -LRB101 09482 JRG 54580 b

1evaluator, and the procurement processes described in this
2Section are exempt from the requirements of the Illinois
3Procurement Code, under Section 20-10 of that Code.
4    (g) All disbursements from the Illinois Power Agency
5Renewable Energy Resources Fund shall be made only upon
6warrants of the Comptroller drawn upon the Treasurer as
7custodian of the Fund upon vouchers signed by the Director or
8by the person or persons designated by the Director for that
9purpose. The Comptroller is authorized to draw the warrant upon
10vouchers so signed. The Treasurer shall accept all warrants so
11signed and shall be released from liability for all payments
12made on those warrants.
13    (h) The Illinois Power Agency Renewable Energy Resources
14Fund shall not be subject to sweeps, administrative charges, or
15chargebacks, including, but not limited to, those authorized
16under Section 8h of the State Finance Act, that would in any
17way result in the transfer of any funds from this Fund to any
18other fund of this State or in having any such funds utilized
19for any purpose other than the express purposes set forth in
20this Section.
21    (h-5) The Agency may assess fees to each bidder to recover
22the costs incurred in connection with a procurement process
23held under this Section. Fees collected from bidders shall be
24deposited into the Renewable Energy Resources Fund.
25    (i) Supplemental procurement process.
26        (1) Within 90 days after the effective date of this

 

 

HB2966- 55 -LRB101 09482 JRG 54580 b

1    amendatory Act of the 98th General Assembly, the Agency
2    shall develop a one-time supplemental procurement plan
3    limited to the procurement of renewable energy credits, if
4    available, from new or existing photovoltaics, including,
5    but not limited to, distributed photovoltaic generation.
6    Nothing in this subsection (i) requires procurement of wind
7    generation through the supplemental procurement.
8        Renewable energy credits procured from new
9    photovoltaics, including, but not limited to, distributed
10    photovoltaic generation, under this subsection (i) must be
11    procured from devices installed by a qualified person. In
12    its supplemental procurement plan, the Agency shall
13    establish contractually enforceable mechanisms for
14    ensuring that the installation of new photovoltaics is
15    performed by a qualified person.
16        For the purposes of this paragraph (1), "qualified
17    person" means a person who performs installations of
18    photovoltaics, including, but not limited to, distributed
19    photovoltaic generation, and who: (A) has completed an
20    apprenticeship as a journeyman electrician from a United
21    States Department of Labor registered electrical
22    apprenticeship and training program and received a
23    certification of satisfactory completion; or (B) does not
24    currently meet the criteria under clause (A) of this
25    paragraph (1), but is enrolled in a United States
26    Department of Labor registered electrical apprenticeship

 

 

HB2966- 56 -LRB101 09482 JRG 54580 b

1    program, provided that the person is directly supervised by
2    a person who meets the criteria under clause (A) of this
3    paragraph (1); or (C) has obtained one of the following
4    credentials in addition to attesting to satisfactory
5    completion of at least 5 years or 8,000 hours of documented
6    hands-on electrical experience: (i) a North American Board
7    of Certified Energy Practitioners (NABCEP) Installer
8    Certificate for Solar PV; (ii) an Underwriters
9    Laboratories (UL) PV Systems Installer Certificate; (iii)
10    an Electronics Technicians Association, International
11    (ETAI) Level 3 PV Installer Certificate; or (iv) an
12    Associate in Applied Science degree from an Illinois
13    Community College Board approved community college program
14    in renewable energy or a distributed generation
15    technology.
16        For the purposes of this paragraph (1), "directly
17    supervised" means that there is a qualified person who
18    meets the qualifications under clause (A) of this paragraph
19    (1) and who is available for supervision and consultation
20    regarding the work performed by persons under clause (B) of
21    this paragraph (1), including a final inspection of the
22    installation work that has been directly supervised to
23    ensure safety and conformity with applicable codes.
24        For the purposes of this paragraph (1), "install" means
25    the major activities and actions required to connect, in
26    accordance with applicable building and electrical codes,

 

 

HB2966- 57 -LRB101 09482 JRG 54580 b

1    the conductors, connectors, and all associated fittings,
2    devices, power outlets, or apparatuses mounted at the
3    premises that are directly involved in delivering energy to
4    the premises' electrical wiring from the photovoltaics,
5    including, but not limited to, to distributed photovoltaic
6    generation.
7        The renewable energy credits procured pursuant to the
8    supplemental procurement plan shall be procured using up to
9    $30,000,000 from the Illinois Power Agency Renewable
10    Energy Resources Fund. The Agency shall not plan to use
11    funds from the Illinois Power Agency Renewable Energy
12    Resources Fund in excess of the monies on deposit in such
13    fund or projected to be deposited into such fund. The
14    supplemental procurement plan shall ensure adequate,
15    reliable, affordable, efficient, and environmentally
16    sustainable renewable energy resources (including credits)
17    at the lowest total cost over time, taking into account any
18    benefits of price stability.
19        To the extent available, 50% of the renewable energy
20    credits procured from distributed renewable energy
21    generation shall come from devices of less than 25
22    kilowatts in nameplate capacity. Procurement of renewable
23    energy credits from distributed renewable energy
24    generation devices shall be done through multi-year
25    contracts of no less than 5 years. The Agency shall create
26    credit requirements for counterparties. In order to

 

 

HB2966- 58 -LRB101 09482 JRG 54580 b

1    minimize the administrative burden on contracting
2    entities, the Agency shall solicit the use of third parties
3    to aggregate distributed renewable energy. These third
4    parties shall enter into and administer contracts with
5    individual distributed renewable energy generation device
6    owners. An individual distributed renewable energy
7    generation device owner shall have the ability to measure
8    the output of his or her distributed renewable energy
9    generation device.
10        In developing the supplemental procurement plan, the
11    Agency shall hold at least one workshop open to the public
12    within 90 days after the effective date of this amendatory
13    Act of the 98th General Assembly and shall consider any
14    comments made by stakeholders or the public. Upon
15    development of the supplemental procurement plan within
16    this 90-day period, copies of the supplemental procurement
17    plan shall be posted and made publicly available on the
18    Agency's and Commission's websites. All interested parties
19    shall have 14 days following the date of posting to provide
20    comment to the Agency on the supplemental procurement plan.
21    All comments submitted to the Agency shall be specific,
22    supported by data or other detailed analyses, and, if
23    objecting to all or a portion of the supplemental
24    procurement plan, accompanied by specific alternative
25    wording or proposals. All comments shall be posted on the
26    Agency's and Commission's websites. Within 14 days

 

 

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

 

 

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

 

 

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

 

 

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

 

 

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

 

 

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

 

 

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1        (7) The names of the successful bidders and the average
2    of the winning bid prices for each contract type and for
3    each contract term shall be made available to the public
4    within 2 days after the supplemental procurement event. The
5    Commission, the procurement monitor, the procurement
6    administrator, the Agency, and all participants in the
7    procurement process shall maintain the confidentiality of
8    all other supplier and bidding information in a manner
9    consistent with all applicable laws, rules, regulations,
10    and tariffs. Confidential information, including the
11    confidential reports submitted by the procurement
12    administrator and procurement monitor pursuant to this
13    Section, shall not be made publicly available and shall not
14    be discoverable by any party in any proceeding, absent a
15    compelling demonstration of need, nor shall those reports
16    be admissible in any proceeding other than one for law
17    enforcement purposes.
18        (8) The supplemental procurement provided in this
19    subsection (i) shall not be subject to the requirements and
20    limitations of subsections (c) and (d) of this Section.
21        (9) Expenses incurred in connection with the
22    procurement process held pursuant to this Section,
23    including, but not limited to, the cost of developing the
24    supplemental procurement plan, the procurement
25    administrator, procurement monitor, and the cost of the
26    retirement of renewable energy credits purchased pursuant

 

 

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1    to the supplemental procurement shall be paid for from the
2    Illinois Power Agency Renewable Energy Resources Fund. The
3    Agency shall enter into an interagency agreement with the
4    Commission to reimburse the Commission for its costs
5    associated with the procurement monitor for the
6    supplemental procurement process.
7(Source: P.A. 98-672, eff. 6-30-14; 99-906, eff. 6-1-17.)
 
8    (20 ILCS 3855/1-75)
9    Sec. 1-75. Planning and Procurement Bureau. The Planning
10and Procurement Bureau has the following duties and
11responsibilities:
12    (a) The Planning and Procurement Bureau shall each year,
13beginning in 2008, develop procurement plans and conduct
14competitive procurement processes in accordance with the
15requirements of Section 16-111.5 of the Public Utilities Act
16for the eligible retail customers of electric utilities that on
17December 31, 2005 provided electric service to at least 100,000
18customers in Illinois. Beginning with the delivery year
19commencing on June 1, 2017, the Planning and Procurement Bureau
20shall develop plans and processes for the procurement of zero
21emission credits from zero emission facilities in accordance
22with the requirements of subsection (d-5) of this Section. The
23Planning and Procurement Bureau shall also develop procurement
24plans and conduct competitive procurement processes in
25accordance with the requirements of Section 16-111.5 of the

 

 

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1Public Utilities Act for the eligible retail customers of small
2multi-jurisdictional electric utilities that (i) on December
331, 2005 served less than 100,000 customers in Illinois and
4(ii) request a procurement plan for their Illinois
5jurisdictional load. This Section shall not apply to a small
6multi-jurisdictional utility until such time as a small
7multi-jurisdictional utility requests the Agency to prepare a
8procurement plan for their Illinois jurisdictional load. For
9the purposes of this Section, the term "eligible retail
10customers" has the same definition as found in Section
1116-111.5(a) of the Public Utilities Act.
12    Beginning with the plan or plans to be implemented in the
132017 delivery year, the Agency shall no longer include the
14procurement of renewable energy resources in the annual
15procurement plans required by this subsection (a), except as
16provided in subsection (q) of Section 16-111.5 of the Public
17Utilities Act, and shall instead develop a long-term renewable
18resources procurement plan in accordance with subsection (c) of
19this Section and Section 16-111.5 of the Public Utilities Act.
20        (1) The Agency shall each year, beginning in 2008, as
21    needed, issue a request for qualifications for experts or
22    expert consulting firms to develop the procurement plans in
23    accordance with Section 16-111.5 of the Public Utilities
24    Act. In order to qualify an expert or expert consulting
25    firm must have:
26            (A) direct previous experience assembling

 

 

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

 

 

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

 

 

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

 

 

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1    consulting firm, with approval of the Commission, to serve
2    as procurement administrator based on the proposals
3    submitted. If the Commission rejects, within 5 days, the
4    Agency's selection, the Agency shall submit another
5    recommendation within 3 days based on the proposals
6    submitted. The Agency shall award a 5-year contract to the
7    expert or expert consulting firm so selected with
8    Commission approval.
9    (b) The experts or expert consulting firms retained by the
10Agency shall, as appropriate, prepare procurement plans, and
11conduct a competitive procurement process as prescribed in
12Section 16-111.5 of the Public Utilities Act, to ensure
13adequate, reliable, affordable, efficient, and environmentally
14sustainable electric service at the lowest total cost over
15time, taking into account any benefits of price stability, for
16eligible retail customers of electric utilities that on
17December 31, 2005 provided electric service to at least 100,000
18customers in the State of Illinois, and for eligible Illinois
19retail customers of small multi-jurisdictional electric
20utilities that (i) on December 31, 2005 served less than
21100,000 customers in Illinois and (ii) request a procurement
22plan for their Illinois jurisdictional load.
23    (c) Renewable portfolio standard.
24        (1)(A) The Agency shall develop a long-term renewable
25    resources procurement plan that shall include procurement
26    programs and competitive procurement events necessary to

 

 

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

 

 

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1    long-term plan shall prioritize compliance with the new
2    wind and new photovoltaic procurement requirements
3    described in items (i) through (iii) of subparagraph (C) of
4    this paragraph (1) over the annual percentage targets
5    described in this subparagraph (B).
6        For the delivery year beginning June 1, 2017, the
7    procurement plan shall include cost-effective renewable
8    energy resources equal to at least 13% of each utility's
9    load for eligible retail customers and 13% of the
10    applicable portion of each utility's load for retail
11    customers who are not eligible retail customers, which
12    applicable portion shall equal 50% of the utility's load
13    for retail customers who are not eligible retail customers
14    on February 28, 2017.
15        For the delivery year beginning June 1, 2018, the
16    procurement plan shall include cost-effective renewable
17    energy resources equal to at least 14.5% of each utility's
18    load for eligible retail customers and 14.5% of the
19    applicable portion of each utility's load for retail
20    customers who are not eligible retail customers, which
21    applicable portion shall equal 75% of the utility's load
22    for retail customers who are not eligible retail customers
23    on February 28, 2017.
24        For the delivery year beginning June 1, 2019, and for
25    each year thereafter, the procurement plans shall include
26    cost-effective renewable energy resources equal to a

 

 

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1    minimum percentage of each utility's load for all retail
2    customers as follows: 16% by June 1, 2019; increasing by
3    1.5% each year thereafter to 25% by June 1, 2025;
4    increasing by at least 2.5% each delivery year thereafter
5    to at least 37.5% by June 1, 2030 and 25% by June 1, 2026
6    and each year thereafter.
7        For each delivery year, the Agency shall first
8    recognize each utility's obligations for that delivery
9    year under existing contracts. Any renewable energy
10    credits under existing contracts, including renewable
11    energy credits as part of renewable energy resources, shall
12    be used to meet the goals set forth in this subsection (c)
13    for the delivery year.
14        (C) Of the renewable energy credits procured under this
15    subsection (c), at least 75% shall come from wind and
16    photovoltaic projects. The long-term renewable resources
17    procurement plan described in subparagraph (A) of this
18    paragraph (1) shall include the procurement of new
19    renewable energy credits in amounts equal to at least
20    10,000,000 renewable energy credits from new wind and solar
21    projects by the end of delivery year 2020, and increasing
22    ratably to reach 45,000,000 new renewable energy credits
23    from wind and solar projects by the end of delivery year
24    2030 such that the goals in subparagraph (B) of this
25    paragraph (1) are met entirely by procurements of new
26    renewable energy credits from wind and solar projects. Of

 

 

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1    the following: (i) By the end of the 2020 delivery year: At
2    least 2,000,000 renewable energy credits for each delivery
3    year shall come from new wind projects; and At least
4    2,000,000 renewable energy credits for each delivery year
5    shall come from new photovoltaic projects; of that amount,
6    to the extent possible, the Agency shall procure: 50% from
7    wind projects and 50% from solar projects. Of the amount
8    procured from solar projects, the Agency shall procure, to
9    the extent reasonably practicable: at least 50% from solar
10    photovoltaic projects using the program outlined in
11    subparagraph (K) of this paragraph (1) from distributed
12    renewable energy generation devices or community renewable
13    generation projects; at least 40% from utility-scale solar
14    projects; at least 2% from brownfield site photovoltaic
15    projects that are not community renewable generation
16    projects; and the remainder shall be determined through the
17    long-term planning process described in subparagraph (A)
18    of this paragraph (1).
19        (ii) By the end of the 2025 delivery year: At least
20    3,000,000 renewable energy credits for each delivery year
21    shall come from new wind projects; and At least 3,000,000
22    renewable energy credits for each delivery year shall come
23    from new photovoltaic projects; of that amount, to the
24    extent possible, the Agency shall procure: at least 50%
25    from solar photovoltaic projects using the program
26    outlined in subparagraph (K) of this paragraph (1) from

 

 

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1    distributed renewable energy devices or community
2    renewable generation projects; at least 40% from
3    utility-scale solar projects; at least 2% from brownfield
4    site photovoltaic projects that are not community
5    renewable generation projects; and the remainder shall be
6    determined through the long-term planning process
7    described in subparagraph (A) of this paragraph (1).
8        (iii) By the end of the 2030 delivery year: At least
9    4,000,000 renewable energy credits for each delivery year
10    shall come from new wind projects; and At least 4,000,000
11    renewable energy credits for each delivery year shall come
12    from new photovoltaic projects; of that amount, to the
13    extent possible, the Agency shall procure: at least 50%
14    from solar photovoltaic projects using the program
15    outlined in subparagraph (K) of this paragraph (1) from
16    distributed renewable energy devices or community
17    renewable generation projects; at least 40% from
18    utility-scale solar projects; at least 2% from brownfield
19    site photovoltaic projects that are not community
20    renewable generation projects; and the remainder shall be
21    determined through the long-term planning process
22    described in subparagraph (A) of this paragraph (1).
23        For purposes of this Section:
24        "New wind projects" means wind renewable energy
25    facilities that are energized after June 1, 2017 for the
26    delivery year commencing June 1, 2017 or within 3 years

 

 

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1    after the date the Commission approves contracts for
2    subsequent delivery years.
3        "New photovoltaic projects" means photovoltaic
4    renewable energy facilities that are energized after June
5    1, 2017. Photovoltaic projects developed under Section
6    1-56 of this Act shall not apply towards the new
7    photovoltaic project requirements in this subparagraph
8    (C). For purposes of calculating whether the Agency has
9    procured enough new wind and solar renewable energy credits
10    required by this subparagraph (C), renewable energy
11    facilities that have a multi-year renewable energy credit
12    delivery contract with the utility through at least
13    delivery year 2030 shall be considered new, however no
14    renewable energy credits from contracts entered into
15    before June 1, 2019 shall be used to calculate whether the
16    Agency has procured the correct proportion of new wind and
17    new solar contracts described in this subparagraph (C) for
18    delivery year 2020 and thereafter.
19        (D) Renewable energy credits shall be cost effective.
20    For purposes of this subsection (c), "cost effective" means
21    that the costs of procuring renewable energy resources do
22    not cause the limit stated in subparagraph (E) of this
23    paragraph (1) to be exceeded and, for renewable energy
24    credits procured through a competitive procurement event,
25    do not exceed benchmarks based on market prices for like
26    products in the region. For purposes of this subsection

 

 

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1    (c), "like products" means contracts for renewable energy
2    credits from the same or substantially similar technology,
3    same or substantially similar vintage (new or existing),
4    the same or substantially similar quantity, and the same or
5    substantially similar contract length and structure.
6    Benchmarks shall be developed by the procurement
7    administrator, in consultation with the Commission staff,
8    Agency staff, and the procurement monitor and shall be
9    subject to Commission review and approval. If price
10    benchmarks for like products in the region are not
11    available, the procurement administrator shall establish
12    price benchmarks based on publicly available data on
13    regional technology costs and expected current and future
14    regional energy prices. The benchmarks in this Section
15    shall not be used to curtail or otherwise reduce
16    contractual obligations entered into by or through the
17    Agency prior to June 1, 2017 (the effective date of Public
18    Act 99-906).
19        (E) For purposes of this subsection (c), the required
20    procurement of cost-effective renewable energy resources
21    for a particular year commencing prior to June 1, 2017
22    shall be measured as a percentage of the actual amount of
23    electricity (megawatt-hours) supplied by the electric
24    utility to eligible retail customers in the delivery year
25    ending immediately prior to the procurement, and, for
26    delivery years commencing on and after June 1, 2017, the

 

 

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1    required procurement of cost-effective renewable energy
2    resources for a particular year shall be measured as a
3    percentage of the actual amount of electricity
4    (megawatt-hours) delivered by the electric utility in the
5    delivery year ending immediately prior to the procurement,
6    to all retail customers in its service territory. For
7    purposes of this subsection (c), the amount paid per
8    kilowatthour means the total amount paid for electric
9    service expressed on a per kilowatthour basis. For purposes
10    of this subsection (c), the total amount paid for electric
11    service includes without limitation amounts paid for
12    supply, capacity, transmission, distribution, surcharges,
13    and add-on taxes.
14        Notwithstanding the requirements of this subsection
15    (c), the total of renewable energy resources procured under
16    the procurement plan for any single year shall be subject
17    to the limitations of this subparagraph (E). Such
18    procurement shall be reduced for all retail customers based
19    on the amount necessary to limit the annual estimated
20    average net increase due to the costs of these resources
21    included in the amounts paid by eligible retail customers
22    in connection with electric service to no more than the
23    greater of the percentage limitations as included in
24    paragraphs (1), (2), and (3) of subsection (m) of Section
25    8-103B of the Public Utilities Act 2.015% of the amount
26    paid per kilowatthour by those customers during the year

 

 

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1    ending May 31, 2009 2007 or the incremental amount per
2    kilowatthour paid for these resources in 2011. To arrive at
3    a maximum dollar amount of renewable energy resources to be
4    procured for the particular delivery year, the resulting
5    per kilowatthour amount shall be applied to the actual
6    amount of kilowatthours of electricity delivered, or
7    applicable portion of such amount as specified in paragraph
8    (1) of this subsection (c), as applicable, by the electric
9    utility in the delivery year immediately prior to the
10    procurement to all retail customers in its service
11    territory. The calculations required by this subparagraph
12    (E) shall be made only once for each delivery year at the
13    time that the renewable energy resources are procured. Once
14    the determination as to the amount of renewable energy
15    resources to procure is made based on the calculations set
16    forth in this subparagraph (E) and the contracts procuring
17    those amounts are executed, no subsequent rate impact
18    determinations shall be made and no adjustments to those
19    contract amounts shall be allowed. All costs incurred under
20    such contracts shall be fully recoverable by the electric
21    utility as provided in this Section.
22        (E-5) If the limitation on the amount of renewable
23    energy resources procured in subparagraph (E) of this
24    paragraph (1) would prevent the Agency from meeting all of
25    the goals in this subsection (c), the Agency shall procure
26    additional renewable energy resources up to an amount equal

 

 

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1    to the Social Cost of Carbon as defined in subsection (d-5)
2    of this Section as of January 1, 2019 multiplied by the
3    amount of new renewable energy credits to be procured
4    pursuant to the new renewable energy credit procurement
5    requirements of subparagraph (C) of this paragraph (1) from
6    the new build requirements for the relevant planning year.
7    The deemed savings of renewable energy shall not be subject
8    to the limitations in subparagraph (E) of this paragraph
9    (1). The utilities shall be entitled to recover the total
10    cost associated with procuring renewable energy credits
11    required by this Section regardless of whether the costs
12    are subject to the limitations described in subparagraph
13    (E) of this paragraph (1) through the automatic adjustment
14    clause tariff under subsection (k) of Section 16-108 of the
15    Public Utilities Act.
16        (F) If the limitation on the amount of renewable energy
17    (1) resources procured in subparagraph (E) of this
18    paragraph (1) prevents the Agency from meeting all of the
19    goals in this subsection (c), the Agency's long-term plan
20    shall prioritize compliance with the requirements of this
21    subsection (c) regarding renewable energy credits in the
22    following order:
23            (i) renewable energy credits under existing
24        contractual obligations;
25            (i-5) funding for the Illinois Solar for All
26        Program, as described in subparagraph (O) of this

 

 

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1        paragraph (1);
2            (ii) renewable energy credits necessary to comply
3        with the new wind and new photovoltaic procurement
4        requirements described in items (i) through (iii) of
5        subparagraph (C) of this paragraph (1); and
6            (iii) renewable energy credits necessary to meet
7        the remaining requirements of this subsection (c).
8        (G) The following provisions shall apply to the
9    Agency's procurement of renewable energy credits under
10    this subsection (c):
11            (i) Notwithstanding whether a long-term renewable
12        resources procurement plan has been approved, the
13        Agency shall conduct an initial forward procurement
14        for renewable energy credits from new utility-scale
15        wind projects within 160 days after June 1, 2017 (the
16        effective date of Public Act 99-906). For the purposes
17        of this initial forward procurement, the Agency shall
18        solicit 15-year contracts for delivery of 1,000,000
19        renewable energy credits delivered annually from new
20        utility-scale wind projects to begin delivery on June
21        1, 2019, if available, but not later than June 1, 2021.
22        Payments to suppliers of renewable energy credits
23        shall commence upon delivery. Renewable energy credits
24        procured under this initial procurement shall be
25        included in the Agency's long-term plan and shall apply
26        to all renewable energy goals in this subsection (c).

 

 

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1            (ii) Notwithstanding whether a long-term renewable
2        resources procurement plan has been approved, the
3        Agency shall conduct an initial forward procurement
4        for renewable energy credits from new utility-scale
5        solar projects and brownfield site photovoltaic
6        projects within one year after June 1, 2017 (the
7        effective date of Public Act 99-906). For the purposes
8        of this initial forward procurement, the Agency shall
9        solicit 15-year contracts for delivery of 1,000,000
10        renewable energy credits delivered annually from new
11        utility-scale solar projects and brownfield site
12        photovoltaic projects to begin delivery on June 1,
13        2019, if available, but not later than June 1, 2021.
14        The Agency may structure this initial procurement in
15        one or more discrete procurement events. Payments to
16        suppliers of renewable energy credits shall commence
17        upon delivery. Renewable energy credits procured under
18        this initial procurement shall be included in the
19        Agency's long-term plan and shall apply to all
20        renewable energy 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

 

 

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1        wind projects and new utility-scale solar projects
2        within 120 days after the effective date of this
3        amendatory Act of the 101st 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.

 

 

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1        Variable price renewable energy credit bids shall be
2        limited to the first 3 new utility-scale wind and solar
3        procurements following the effective date of this
4        amendatory act of the 101st General Assembly. Variable
5        renewable energy credit bids shall be based on the
6        difference between the offer strike price and the index
7        price that shall be developed by the Illinois Power
8        Agency and approved by the Illinois Commerce
9        Commission. Variable price renewable energy credits
10        shall not exceed more than 40% or less than 20% of the
11        total supply for new utility-scale wind and solar
12        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 of
20        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 shall
26        within 60 days adjust the procurement programs in the

 

 

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1        long-term renewable resources procurement plan to
2        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 from
6        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 from
10        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 in
14        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 follow

 

 

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1        the procurement processes and procedures described in
2        this Section and Section 16-111.5 of the Public
3        Utilities Act to the extent practicable, and these
4        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 a
8    given delivery year shall be reduced as described in this
9    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

 

 

HB2966- 88 -LRB101 09482 JRG 54580 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 retail
5        customers with renewable energy credits from the
6        facility or facilities described in item (i) of this
7        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 is
14        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 the
20        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

 

 

HB2966- 89 -LRB101 09482 JRG 54580 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

 

 

HB2966- 90 -LRB101 09482 JRG 54580 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 by
16        the alternative retail electric supplier compared to
17        that supplier's target renewable energy credit
18        quantity. The supplier's target renewable energy
19        credit quantity for the delivery year beginning June 1,
20        2018 is 14.5% multiplied by the total amount of metered
21        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.

 

 

HB2966- 91 -LRB101 09482 JRG 54580 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 in
8    the health, safety, and welfare of its residents, including
9    but not limited to minimizing sulfur dioxide, nitrogen
10    oxide, particulate matter and other pollution that
11    adversely affects public health in this State, increasing
12    fuel and resource diversity in this State, enhancing the
13    reliability and resiliency of the electricity distribution
14    system in this State, meeting goals to limit carbon dioxide
15    emissions under federal or State law, and contributing to a
16    cleaner and healthier environment for the citizens of this
17    State. In order to further these legislative purposes,
18    renewable energy credits shall be eligible to be counted
19    toward the renewable energy requirements of this
20    subsection (c) if they are generated from facilities
21    located in this State. The Agency may qualify renewable
22    energy credits from facilities located in states adjacent
23    to Illinois if the generator demonstrates and the Agency
24    determines that the operation of such facility or
25    facilities will help promote the State's interest in the
26    health, safety, and welfare of its residents based on the

 

 

HB2966- 92 -LRB101 09482 JRG 54580 b

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

 

 

HB2966- 93 -LRB101 09482 JRG 54580 b

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

 

 

HB2966- 94 -LRB101 09482 JRG 54580 b

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

 

 

HB2966- 95 -LRB101 09482 JRG 54580 b

1        The Agency may periodically review its prior decisions
2    establishing the number of blocks, the amount of generation
3    capacity in each block, and the purchase price for each
4    block, and may propose, on an expedited basis, changes to
5    these previously set values, including but not limited to
6    redistributing these amounts and the available funds as
7    necessary and appropriate, subject to Commission approval
8    as part of the periodic plan revision process described in
9    Section 16-111.5 of the Public Utilities Act. The Agency
10    may define different block sizes, purchase prices, or other
11    distinct terms and conditions for projects located in
12    different utility service territories if the Agency deems
13    it necessary to meet the goals in this subsection (c).
14        The Adjustable Block program shall include at least the
15    following block groups in at least the following amounts,
16    which may be adjusted upon review by the Agency and
17    approval by the Commission as described in this
18    subparagraph (K):
19            (i) At least 25% from distributed renewable energy
20        generation devices with a nameplate capacity of no more
21        than 25 10 kilowatts.
22            (ii) At least 25% from distributed renewable
23        energy generation devices with a nameplate capacity of
24        more than 25 10 kilowatts and no more than 2,000
25        kilowatts. The Agency may create sub-categories within
26        this category to account for the differences between

 

 

HB2966- 96 -LRB101 09482 JRG 54580 b

1        projects for small commercial customers, large
2        commercial customers, and public or non-profit
3        customers.
4            (iii) At least 25% from photovoltaic community
5        renewable generation projects.
6            (iv) The remaining 25% shall be allocated as
7        specified by the Agency in the long-term renewable
8        resources procurement plan in order to respond to
9        market demand.
10        The Adjustable Block program shall be designed to
11    ensure that renewable energy credits are procured from
12    photovoltaic distributed renewable energy generation
13    devices and new photovoltaic community renewable energy
14    generation projects in diverse locations and are not
15    concentrated in a few geographic areas.
16        (L) The procurement of photovoltaic renewable energy
17    credits under items (i) through (iv) of subparagraph (K) of
18    this paragraph (1) shall be subject to the following
19    contract and payment terms:
20            (i) The Agency shall procure contracts of at least
21        15 years in length.
22            (ii) For those renewable energy credits that
23        qualify and are procured under item (i) of subparagraph
24        (K) of this paragraph (1), the renewable energy credit
25        purchase price shall be paid in full by the contracting
26        utilities at the time that the facility producing the

 

 

HB2966- 97 -LRB101 09482 JRG 54580 b

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

 

 

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1        described in Section 16-111.5 of the Public Utilities
2        Act. No contract shall be executed for an amount that
3        is less than one renewable energy credit per year.
4            (vi) If, at any time, approved applications for the
5        Adjustable Block program exceed funds collected by the
6        electric utility or would cause the Agency to exceed
7        the limitation described in subparagraph (E) of this
8        paragraph (1) on the amount of renewable energy
9        resources that may be procured, then the Agency shall
10        consider future uncommitted funds to be reserved for
11        these contracts on a first-come, first-served basis,
12        with the delivery of renewable energy credits required
13        beginning at the time that the reserved funds become
14        available.
15            (vii) Nothing in this Section shall require the
16        utility to advance any payment or pay any amounts that
17        exceed the actual amount of revenues collected by the
18        utility under paragraph (6) of this subsection (c) and
19        subsection (k) of Section 16-108 of the Public
20        Utilities Act, and contracts executed under this
21        Section shall expressly incorporate this limitation.
22            (viii) Notwithstanding items (ii) and (iii) of
23        this subparagraph (L), the Agency shall not be
24        restricted from offering additional payment structures
25        if it determines that such adjustments will better
26        achieve the goals of this subsection (c). Any such

 

 

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1        adjustments shall be approved by the Commission as a
2        long-term plan amendment under Section 16-111.5 of the
3        Public Utilities Act.
4        (M) The Agency shall be authorized to retain one or
5    more experts or expert consulting firms to develop,
6    administer, implement, operate, and evaluate the
7    Adjustable Block program described in subparagraph (K) of
8    this paragraph (1), and the Agency shall retain the
9    consultant or consultants in the same manner, to the extent
10    practicable, as the Agency retains others to administer
11    provisions of this Act, including, but not limited to, the
12    procurement administrator. The selection of experts and
13    expert consulting firms and the procurement process
14    described in this subparagraph (M) are exempt from the
15    requirements of Section 20-10 of the Illinois Procurement
16    Code, under Section 20-10 of that Code. The Agency shall
17    strive to minimize administrative expenses in the
18    implementation of the Adjustable Block program. Funds
19    needed to cover the administrative expenses for the
20    implementation of the Adjustable Block program shall not be
21    included as part of the limitations described in
22    subparagraph (E). The utilities shall be entitled to
23    recover the costs detailed in this subparagraph (M)
24    regardless of whether the costs are subject to the
25    limitations described in subparagraph (E) through the
26    automatic adjustment clause tariff under subsection (k) of

 

 

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1    Section 16-108 of the Public Utilities Act.
2        The Agency and its consultant or consultants shall
3    monitor block activity, share program activity with
4    stakeholders and conduct regularly scheduled meetings to
5    discuss program activity and market conditions. If
6    necessary, the Agency may make prospective administrative
7    adjustments to the Adjustable Block program design, such as
8    redistributing available funds or making adjustments to
9    purchase prices as necessary to achieve the goals of this
10    subsection (c). Program modifications to any price,
11    capacity block, or other program element that do not
12    deviate from the Commission's approved value by more than
13    25% shall take effect immediately and are not subject to
14    Commission review and approval. Program modifications to
15    any price, capacity block, or other program element that
16    deviate more than 25% from the Commission's approved value
17    must be approved by the Commission as a long-term plan
18    amendment under Section 16-111.5 of the Public Utilities
19    Act. The Agency shall consider stakeholder feedback when
20    making adjustments to the Adjustable Block design and shall
21    notify stakeholders in advance of any planned changes.
22        (N) The long-term renewable resources procurement plan
23    required by this subsection (c) shall include a community
24    renewable generation program. The Agency shall establish
25    the terms, conditions, and program requirements for
26    community renewable generation projects with a goal to

 

 

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1    expand renewable energy generating facility access to a
2    broader group of energy consumers, to ensure robust
3    participation opportunities for residential and small
4    commercial customers and those who cannot install
5    renewable energy on their own properties. Any plan approved
6    by the Commission shall allow subscriptions to community
7    renewable generation projects to be portable and
8    transferable. For purposes of this subparagraph (N),
9    "portable" means that subscriptions may be retained by the
10    subscriber even if the subscriber relocates or changes its
11    address within the same utility service territory; and
12    "transferable" means that a subscriber may assign or sell
13    subscriptions to another person within the same utility
14    service territory.
15        Electric utilities shall provide a monetary credit to a
16    subscriber's subsequent bill for service for the
17    proportional output of a community renewable generation
18    project attributable to that subscriber as specified in
19    Section 16-107.5 of the Public Utilities Act.
20        The Agency shall purchase renewable energy credits
21    from subscribed shares of photovoltaic community renewable
22    generation projects through the Adjustable Block program
23    described in subparagraph (K) of this paragraph (1) or
24    through the Illinois Solar for All Program described in
25    Section 1-56 of this Act. The project shall be deemed to be
26    fully subscribed and the Agency shall purchase all of the

 

 

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1    renewable energy credits from photovoltaic community
2    renewable generation projects as long as a minimum of 80%
3    of the shares are subscribed. The electric utility shall
4    purchase any unsubscribed energy from community renewable
5    generation projects that are Qualifying Facilities ("QF")
6    under the electric utility's tariff for purchasing the
7    output from QFs under Public Utilities Regulatory Policies
8    Act of 1978.
9        The owners of and any subscribers to a community
10    renewable generation project shall not be considered
11    public utilities or alternative retail electricity
12    suppliers under the Public Utilities Act solely as a result
13    of their interest in or subscription to a community
14    renewable generation project and shall not be required to
15    become an alternative retail electric supplier by
16    participating in a community renewable generation project
17    with a public utility.
18        (O) For the delivery year beginning June 1, 2018, the
19    long-term renewable resources procurement plan required by
20    this subsection (c) shall provide for the Agency to procure
21    contracts to continue offering the Illinois Solar for All
22    Program described in subsection (b) of Section 1-56 of this
23    Act, and the contracts approved by the Commission shall be
24    executed by the utilities that are subject to this
25    subsection (c). The long-term renewable resources
26    procurement plan shall allocate $50,000,000 5% of the funds

 

 

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1    available under the plan for the applicable delivery year,
2    or $10,000,000 per delivery year, whichever is greater, to
3    fund the programs, and the plan shall determine the amount
4    of funding to be apportioned to the programs identified in
5    subsection (b) of Section 1-56 of this Act; provided that
6    for the delivery years beginning June 1, 2017, June 1,
7    2021, and June 1, 2025, the long-term renewable resources
8    procurement plan shall allocate an additional 10% of the
9    funds available under the plan for the applicable delivery
10    year, or $20,000,000 per delivery year, whichever is
11    greater, and $10,000,000 that of such funds in such year
12    shall be used by an electric utility that serves more than
13    3,000,000 retail customers in the State to implement a
14    Commission-approved plan under Section 16-108.12 of the
15    Public Utilities Act. Funds allocated under this
16    subparagraph (O) shall not be included as part of the
17    limitations described in subparagraph (E) of this Section.
18    The utilities shall be entitled to recover the total cost
19    associated with procuring renewable energy credits
20    detailed in this subparagraph (O) regardless of whether the
21    costs are subject to the limitations described in
22    subparagraph (E) through the automatic adjustment clause
23    tariff under subsection (k) of Section 16-108 of the Public
24    Utilities Act. In making the determinations required under
25    this subparagraph (O), the Commission shall consider the
26    experience and performance under the programs and any

 

 

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

 

 

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1        (4) The electric utility shall retire all renewable
2    energy credits used to comply with the standard.
3        (5) Beginning with the 2010 delivery year and ending
4    June 1, 2017, an electric utility subject to this
5    subsection (c) shall apply the lesser of the maximum
6    alternative compliance payment rate or the most recent
7    estimated alternative compliance payment rate for its
8    service territory for the corresponding compliance period,
9    established pursuant to subsection (d) of Section 16-115D
10    of the Public Utilities Act to its retail customers that
11    take service pursuant to the electric utility's hourly
12    pricing tariff or tariffs. The electric utility shall
13    retain all amounts collected as a result of the application
14    of the alternative compliance payment rate or rates to such
15    customers, and, beginning in 2011, the utility shall
16    include in the information provided under item (1) of
17    subsection (d) of Section 16-111.5 of the Public Utilities
18    Act the amounts collected under the alternative compliance
19    payment rate or rates for the prior year ending May 31.
20    Notwithstanding any limitation on the procurement of
21    renewable energy resources imposed by item (2) of this
22    subsection (c), the Agency shall increase its spending on
23    the purchase of renewable energy resources to be procured
24    by the electric utility for the next plan year by an amount
25    equal to the amounts collected by the utility under the
26    alternative compliance payment rate or rates in the prior

 

 

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1    year ending May 31.
2        (6) The electric utility shall be entitled to recover
3    all of its costs associated with the procurement of
4    renewable energy credits under plans approved under this
5    Section and Section 16-111.5 of the Public Utilities Act.
6    These costs shall include associated reasonable expenses
7    for implementing the procurement programs, including, but
8    not limited to, the costs of administering and evaluating
9    the Adjustable Block program, through an automatic
10    adjustment clause tariff in accordance with subsection (k)
11    of Section 16-108 of the Public Utilities Act. The costs
12    associated with implementing procurement programs,
13    including, but not limited to, the costs of administering
14    and evaluating the Adjustable Block program, shall not be
15    included as part of the limitations described in
16    subparagraph (E) of paragraph (1).
17        (7) Renewable energy credits procured from new
18    photovoltaic projects or new distributed renewable energy
19    generation devices under this Section after June 1, 2017
20    (the effective date of Public Act 99-906) must be procured
21    from devices installed by a qualified person in compliance
22    with the requirements of Section 16-128A of the Public
23    Utilities Act and any rules or regulations adopted
24    thereunder.
25        In meeting the renewable energy requirements of this
26    subsection (c), to the extent feasible and consistent with

 

 

HB2966- 107 -LRB101 09482 JRG 54580 b

1    State and federal law, the renewable energy credit
2    procurements, Adjustable Block solar program, and
3    community renewable generation program shall provide
4    employment opportunities for all segments of the
5    population and workforce, including minority-owned and
6    female-owned business enterprises, and shall not,
7    consistent with State and federal law, discriminate based
8    on race or socioeconomic status.
9    (d) Clean coal portfolio standard.
10        (1) The procurement plans shall include electricity
11    generated using clean coal. Each utility shall enter into
12    one or more sourcing agreements with the initial clean coal
13    facility, as provided in paragraph (3) of this subsection
14    (d), covering electricity generated by the initial clean
15    coal facility representing at least 5% of each utility's
16    total supply to serve the load of eligible retail customers
17    in 2015 and each year thereafter, as described in paragraph
18    (3) of this subsection (d), subject to the limits specified
19    in paragraph (2) of this subsection (d). It is the goal of
20    the State that by January 1, 2025, 25% of the electricity
21    used in the State shall be generated by cost-effective
22    clean coal facilities. For purposes of this subsection (d),
23    "cost-effective" means that the expenditures pursuant to
24    such sourcing agreements do not cause the limit stated in
25    paragraph (2) of this subsection (d) to be exceeded and do
26    not exceed cost-based benchmarks, which shall be developed

 

 

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1    to assess all expenditures pursuant to such sourcing
2    agreements covering electricity generated by clean coal
3    facilities, other than the initial clean coal facility, by
4    the procurement administrator, in consultation with the
5    Commission staff, Agency staff, and the procurement
6    monitor and shall be subject to Commission review and
7    approval.
8        A utility party to a sourcing agreement shall
9    immediately retire any emission credits that it receives in
10    connection with the electricity covered by such agreement.
11        Utilities shall maintain adequate records documenting
12    the purchases under the sourcing agreement to comply with
13    this subsection (d) and shall file an accounting with the
14    load forecast that must be filed with the Agency by July 15
15    of each year, in accordance with subsection (d) of Section
16    16-111.5 of the Public Utilities Act.
17        A utility shall be deemed to have complied with the
18    clean coal portfolio standard specified in this subsection
19    (d) if the utility enters into a sourcing agreement as
20    required by this subsection (d).
21        (2) For purposes of this subsection (d), the required
22    execution of sourcing agreements with the initial clean
23    coal facility for a particular year shall be measured as a
24    percentage of the actual amount of electricity
25    (megawatt-hours) supplied by the electric utility to
26    eligible retail customers in the planning year ending

 

 

HB2966- 109 -LRB101 09482 JRG 54580 b

1    immediately prior to the agreement's execution. For
2    purposes of this subsection (d), the amount paid per
3    kilowatthour means the total amount paid for electric
4    service expressed on a per kilowatthour basis. For purposes
5    of this subsection (d), the total amount paid for electric
6    service includes without limitation amounts paid for
7    supply, transmission, distribution, surcharges and add-on
8    taxes.
9        Notwithstanding the requirements of this subsection
10    (d), the total amount paid under sourcing agreements with
11    clean coal facilities pursuant to the procurement plan for
12    any given year shall be reduced by an amount necessary to
13    limit the annual estimated average net increase due to the
14    costs of these resources included in the amounts paid by
15    eligible retail customers in connection with electric
16    service to:
17            (A) in 2010, no more than 0.5% of the amount paid
18        per kilowatthour by those customers during the year
19        ending May 31, 2009;
20            (B) in 2011, the greater of an additional 0.5% of
21        the amount paid per kilowatthour by those customers
22        during the year ending May 31, 2010 or 1% of the amount
23        paid per kilowatthour by those customers during the
24        year ending May 31, 2009;
25            (C) in 2012, the greater of an additional 0.5% of
26        the amount paid per kilowatthour by those customers

 

 

HB2966- 110 -LRB101 09482 JRG 54580 b

1        during the year ending May 31, 2011 or 1.5% of the
2        amount paid per kilowatthour by those customers during
3        the year ending May 31, 2009;
4            (D) in 2013, the greater of an additional 0.5% of
5        the amount paid per kilowatthour by those customers
6        during the year ending May 31, 2012 or 2% of the amount
7        paid per kilowatthour by those customers during the
8        year ending May 31, 2009; and
9            (E) thereafter, the total amount paid under
10        sourcing agreements with clean coal facilities
11        pursuant to the procurement plan for any single year
12        shall be reduced by an amount necessary to limit the
13        estimated average net increase due to the cost of these
14        resources included in the amounts paid by eligible
15        retail customers in connection with electric service
16        to no more than the greater of (i) 2.015% of the amount
17        paid per kilowatthour by those customers during the
18        year ending May 31, 2009 or (ii) the incremental amount
19        per kilowatthour paid for these resources in 2013.
20        These requirements may be altered only as provided by
21        statute.
22        No later than June 30, 2015, the Commission shall
23    review the limitation on the total amount paid under
24    sourcing agreements, if any, with clean coal facilities
25    pursuant to this subsection (d) and report to the General
26    Assembly its findings as to whether that limitation unduly

 

 

HB2966- 111 -LRB101 09482 JRG 54580 b

1    constrains the amount of electricity generated by
2    cost-effective clean coal facilities that is covered by
3    sourcing agreements.
4        (3) Initial clean coal facility. In order to promote
5    development of clean coal facilities in Illinois, each
6    electric utility subject to this Section shall execute a
7    sourcing agreement to source electricity from a proposed
8    clean coal facility in Illinois (the "initial clean coal
9    facility") that will have a nameplate capacity of at least
10    500 MW when commercial operation commences, that has a
11    final Clean Air Act permit on June 1, 2009 (the effective
12    date of Public Act 95-1027), and that will meet the
13    definition of clean coal facility in Section 1-10 of this
14    Act when commercial operation commences. The sourcing
15    agreements with this initial clean coal facility shall be
16    subject to both approval of the initial clean coal facility
17    by the General Assembly and satisfaction of the
18    requirements of paragraph (4) of this subsection (d) and
19    shall be executed within 90 days after any such approval by
20    the General Assembly. The Agency and the Commission shall
21    have authority to inspect all books and records associated
22    with the initial clean coal facility during the term of
23    such a sourcing agreement. A utility's sourcing agreement
24    for electricity produced by the initial clean coal facility
25    shall include:
26            (A) a formula contractual price (the "contract

 

 

HB2966- 112 -LRB101 09482 JRG 54580 b

1        price") approved pursuant to paragraph (4) of this
2        subsection (d), which shall:
3                (i) be determined using a cost of service
4            methodology employing either a level or deferred
5            capital recovery component, based on a capital
6            structure consisting of 45% equity and 55% debt,
7            and a return on equity as may be approved by the
8            Federal Energy Regulatory Commission, which in any
9            case may not exceed the lower of 11.5% or the rate
10            of return approved by the General Assembly
11            pursuant to paragraph (4) of this subsection (d);
12            and
13                (ii) provide that all miscellaneous net
14            revenue, including but not limited to net revenue
15            from the sale of emission allowances, if any,
16            substitute natural gas, if any, grants or other
17            support provided by the State of Illinois or the
18            United States Government, firm transmission
19            rights, if any, by-products produced by the
20            facility, energy or capacity derived from the
21            facility and not covered by a sourcing agreement
22            pursuant to paragraph (3) of this subsection (d) or
23            item (5) of subsection (d) of Section 16-115 of the
24            Public Utilities Act, whether generated from the
25            synthesis gas derived from coal, from SNG, or from
26            natural gas, shall be credited against the revenue

 

 

HB2966- 113 -LRB101 09482 JRG 54580 b

1            requirement for this initial clean coal facility;
2            (B) power purchase provisions, which shall:
3                (i) provide that the utility party to such
4            sourcing agreement shall pay the contract price
5            for electricity delivered under such sourcing
6            agreement;
7                (ii) require delivery of electricity to the
8            regional transmission organization market of the
9            utility that is party to such sourcing agreement;
10                (iii) require the utility party to such
11            sourcing agreement to buy from the initial clean
12            coal facility in each hour an amount of energy
13            equal to all clean coal energy made available from
14            the initial clean coal facility during such hour
15            times a fraction, the numerator of which is such
16            utility's retail market sales of electricity
17            (expressed in kilowatthours sold) in the State
18            during the prior calendar month and the
19            denominator of which is the total retail market
20            sales of electricity (expressed in kilowatthours
21            sold) in the State by utilities during such prior
22            month and the sales of electricity (expressed in
23            kilowatthours sold) in the State by alternative
24            retail electric suppliers during such prior month
25            that are subject to the requirements of this
26            subsection (d) and paragraph (5) of subsection (d)

 

 

HB2966- 114 -LRB101 09482 JRG 54580 b

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

 

 

HB2966- 115 -LRB101 09482 JRG 54580 b

1            subsection (d) and paragraph (5) of subsection (d)
2            of Section 16-115 of the Public Utilities Act,
3            provided that the amount paid by the utility in any
4            year will be limited by paragraph (2) of this
5            subsection (d);
6                (ii) provide that the utility's payment
7            obligation in respect of the quantity of
8            electricity determined pursuant to the preceding
9            clause (i) shall be limited to an amount equal to
10            (1) the difference between the contract price
11            determined pursuant to subparagraph (A) of
12            paragraph (3) of this subsection (d) and the
13            day-ahead price for electricity delivered to the
14            regional transmission organization market of the
15            utility that is party to such sourcing agreement
16            (or any successor delivery point at which such
17            utility's supply obligations are financially
18            settled on an hourly basis) (the "reference
19            price") on the day preceding the day on which the
20            electricity is delivered to the initial clean coal
21            facility busbar, multiplied by (2) the quantity of
22            electricity determined pursuant to the preceding
23            clause (i); and
24                (iii) not require the utility to take physical
25            delivery of the electricity produced by the
26            facility;

 

 

HB2966- 116 -LRB101 09482 JRG 54580 b

1            (D) general provisions, which shall:
2                (i) specify a term of no more than 30 years,
3            commencing on the commercial operation date of the
4            facility;
5                (ii) provide that utilities shall maintain
6            adequate records documenting purchases under the
7            sourcing agreements entered into to comply with
8            this subsection (d) and shall file an accounting
9            with the load forecast that must be filed with the
10            Agency by July 15 of each year, in accordance with
11            subsection (d) of Section 16-111.5 of the Public
12            Utilities Act;
13                (iii) provide that all costs associated with
14            the initial clean coal facility will be
15            periodically reported to the Federal Energy
16            Regulatory Commission and to purchasers in
17            accordance with applicable laws governing
18            cost-based wholesale power contracts;
19                (iv) permit the Illinois Power Agency to
20            assume ownership of the initial clean coal
21            facility, without monetary consideration and
22            otherwise on reasonable terms acceptable to the
23            Agency, if the Agency so requests no less than 3
24            years prior to the end of the stated contract term;
25                (v) require the owner of the initial clean coal
26            facility to provide documentation to the

 

 

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1            Commission each year, starting in the facility's
2            first year of commercial operation, accurately
3            reporting the quantity of carbon emissions from
4            the facility that have been captured and
5            sequestered and report any quantities of carbon
6            released from the site or sites at which carbon
7            emissions were sequestered in prior years, based
8            on continuous monitoring of such sites. If, in any
9            year after the first year of commercial operation,
10            the owner of the facility fails to demonstrate that
11            the initial clean coal facility captured and
12            sequestered at least 50% of the total carbon
13            emissions that the facility would otherwise emit
14            or that sequestration of emissions from prior
15            years has failed, resulting in the release of
16            carbon dioxide into the atmosphere, the owner of
17            the facility must offset excess emissions. Any
18            such carbon offsets must be permanent, additional,
19            verifiable, real, located within the State of
20            Illinois, and legally and practicably enforceable.
21            The cost of such offsets for the facility that are
22            not recoverable shall not exceed $15 million in any
23            given year. No costs of any such purchases of
24            carbon offsets may be recovered from a utility or
25            its customers. All carbon offsets purchased for
26            this purpose and any carbon emission credits

 

 

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1            associated with sequestration of carbon from the
2            facility must be permanently retired. The initial
3            clean coal facility shall not forfeit its
4            designation as a clean coal facility if the
5            facility fails to fully comply with the applicable
6            carbon sequestration requirements in any given
7            year, provided the requisite offsets are
8            purchased. However, the Attorney General, on
9            behalf of the People of the State of Illinois, may
10            specifically enforce the facility's sequestration
11            requirement and the other terms of this contract
12            provision. Compliance with the sequestration
13            requirements and offset purchase requirements
14            specified in paragraph (3) of this subsection (d)
15            shall be reviewed annually by an independent
16            expert retained by the owner of the initial clean
17            coal facility, with the advance written approval
18            of the Attorney General. The Commission may, in the
19            course of the review specified in item (vii),
20            reduce the allowable return on equity for the
21            facility if the facility willfully fails to comply
22            with the carbon capture and sequestration
23            requirements set forth in this item (v);
24                (vi) include limits on, and accordingly
25            provide for modification of, the amount the
26            utility is required to source under the sourcing

 

 

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1            agreement consistent with paragraph (2) of this
2            subsection (d);
3                (vii) require Commission review: (1) to
4            determine the justness, reasonableness, and
5            prudence of the inputs to the formula referenced in
6            subparagraphs (A)(i) through (A)(iii) of paragraph
7            (3) of this subsection (d), prior to an adjustment
8            in those inputs including, without limitation, the
9            capital structure and return on equity, fuel
10            costs, and other operations and maintenance costs
11            and (2) to approve the costs to be passed through
12            to customers under the sourcing agreement by which
13            the utility satisfies its statutory obligations.
14            Commission review shall occur no less than every 3
15            years, regardless of whether any adjustments have
16            been proposed, and shall be completed within 9
17            months;
18                (viii) limit the utility's obligation to such
19            amount as the utility is allowed to recover through
20            tariffs filed with the Commission, provided that
21            neither the clean coal facility nor the utility
22            waives any right to assert federal pre-emption or
23            any other argument in response to a purported
24            disallowance of recovery costs;
25                (ix) limit the utility's or alternative retail
26            electric supplier's obligation to incur any

 

 

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1            liability until such time as the facility is in
2            commercial operation and generating power and
3            energy and such power and energy is being delivered
4            to the facility busbar;
5                (x) provide that the owner or owners of the
6            initial clean coal facility, which is the
7            counterparty to such sourcing agreement, shall
8            have the right from time to time to elect whether
9            the obligations of the utility party thereto shall
10            be governed by the power purchase provisions or the
11            contract for differences provisions;
12                (xi) append documentation showing that the
13            formula rate and contract, insofar as they relate
14            to the power purchase provisions, have been
15            approved by the Federal Energy Regulatory
16            Commission pursuant to Section 205 of the Federal
17            Power Act;
18                (xii) provide that any changes to the terms of
19            the contract, insofar as such changes relate to the
20            power purchase provisions, are subject to review
21            under the public interest standard applied by the
22            Federal Energy Regulatory Commission pursuant to
23            Sections 205 and 206 of the Federal Power Act; and
24                (xiii) conform with customary lender
25            requirements in power purchase agreements used as
26            the basis for financing non-utility generators.

 

 

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1        (4) Effective date of sourcing agreements with the
2    initial clean coal facility. Any proposed sourcing
3    agreement with the initial clean coal facility shall not
4    become effective unless the following reports are prepared
5    and submitted and authorizations and approvals obtained:
6            (i) Facility cost report. The owner of the initial
7        clean coal facility shall submit to the Commission, the
8        Agency, and the General Assembly a front-end
9        engineering and design study, a facility cost report,
10        method of financing (including but not limited to
11        structure and associated costs), and an operating and
12        maintenance cost quote for the facility (collectively
13        "facility cost report"), which shall be prepared in
14        accordance with the requirements of this paragraph (4)
15        of subsection (d) of this Section, and shall provide
16        the Commission and the Agency access to the work
17        papers, relied upon documents, and any other backup
18        documentation related to the facility cost report.
19            (ii) Commission report. Within 6 months following
20        receipt of the facility cost report, the Commission, in
21        consultation with the Agency, shall submit a report to
22        the General Assembly setting forth its analysis of the
23        facility cost report. Such report shall include, but
24        not be limited to, a comparison of the costs associated
25        with electricity generated by the initial clean coal
26        facility to the costs associated with electricity

 

 

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1        generated by other types of generation facilities, an
2        analysis of the rate impacts on residential and small
3        business customers over the life of the sourcing
4        agreements, and an analysis of the likelihood that the
5        initial clean coal facility will commence commercial
6        operation by and be delivering power to the facility's
7        busbar by 2016. To assist in the preparation of its
8        report, the Commission, in consultation with the
9        Agency, may hire one or more experts or consultants,
10        the costs of which shall be paid for by the owner of
11        the initial clean coal facility. The Commission and
12        Agency may begin the process of selecting such experts
13        or consultants prior to receipt of the facility cost
14        report.
15            (iii) General Assembly approval. The proposed
16        sourcing agreements shall not take effect unless,
17        based on the facility cost report and the Commission's
18        report, the General Assembly enacts authorizing
19        legislation approving (A) the projected price, stated
20        in cents per kilowatthour, to be charged for
21        electricity generated by the initial clean coal
22        facility, (B) the projected impact on residential and
23        small business customers' bills over the life of the
24        sourcing agreements, and (C) the maximum allowable
25        return on equity for the project; and
26            (iv) Commission review. If the General Assembly

 

 

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1        enacts authorizing legislation pursuant to
2        subparagraph (iii) approving a sourcing agreement, the
3        Commission shall, within 90 days of such enactment,
4        complete a review of such sourcing agreement. During
5        such time period, the Commission shall implement any
6        directive of the General Assembly, resolve any
7        disputes between the parties to the sourcing agreement
8        concerning the terms of such agreement, approve the
9        form of such agreement, and issue an order finding that
10        the sourcing agreement is prudent and reasonable.
11        The facility cost report shall be prepared as follows:
12            (A) The facility cost report shall be prepared by
13        duly licensed engineering and construction firms
14        detailing the estimated capital costs payable to one or
15        more contractors or suppliers for the engineering,
16        procurement and construction of the components
17        comprising the initial clean coal facility and the
18        estimated costs of operation and maintenance of the
19        facility. The facility cost report shall include:
20                (i) an estimate of the capital cost of the core
21            plant based on one or more front end engineering
22            and design studies for the gasification island and
23            related facilities. The core plant shall include
24            all civil, structural, mechanical, electrical,
25            control, and safety systems.
26                (ii) an estimate of the capital cost of the

 

 

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1            balance of the plant, including any capital costs
2            associated with sequestration of carbon dioxide
3            emissions and all interconnects and interfaces
4            required to operate the facility, such as
5            transmission of electricity, construction or
6            backfeed power supply, pipelines to transport
7            substitute natural gas or carbon dioxide, potable
8            water supply, natural gas supply, water supply,
9            water discharge, landfill, access roads, and coal
10            delivery.
11            The quoted construction costs shall be expressed
12        in nominal dollars as of the date that the quote is
13        prepared and shall include capitalized financing costs
14        during construction, taxes, insurance, and other
15        owner's costs, and an assumed escalation in materials
16        and labor beyond the date as of which the construction
17        cost quote is expressed.
18            (B) The front end engineering and design study for
19        the gasification island and the cost study for the
20        balance of plant shall include sufficient design work
21        to permit quantification of major categories of
22        materials, commodities and labor hours, and receipt of
23        quotes from vendors of major equipment required to
24        construct and operate the clean coal facility.
25            (C) The facility cost report shall also include an
26        operating and maintenance cost quote that will provide

 

 

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1        the estimated cost of delivered fuel, personnel,
2        maintenance contracts, chemicals, catalysts,
3        consumables, spares, and other fixed and variable
4        operations and maintenance costs. The delivered fuel
5        cost estimate will be provided by a recognized third
6        party expert or experts in the fuel and transportation
7        industries. The balance of the operating and
8        maintenance cost quote, excluding delivered fuel
9        costs, will be developed based on the inputs provided
10        by duly licensed engineering and construction firms
11        performing the construction cost quote, potential
12        vendors under long-term service agreements and plant
13        operating agreements, or recognized third party plant
14        operator or operators.
15            The operating and maintenance cost quote
16        (including the cost of the front end engineering and
17        design study) shall be expressed in nominal dollars as
18        of the date that the quote is prepared and shall
19        include taxes, insurance, and other owner's costs, and
20        an assumed escalation in materials and labor beyond the
21        date as of which the operating and maintenance cost
22        quote is expressed.
23            (D) The facility cost report shall also include an
24        analysis of the initial clean coal facility's ability
25        to deliver power and energy into the applicable
26        regional transmission organization markets and an

 

 

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1        analysis of the expected capacity factor for the
2        initial clean coal facility.
3            (E) Amounts paid to third parties unrelated to the
4        owner or owners of the initial clean coal facility to
5        prepare the core plant construction cost quote,
6        including the front end engineering and design study,
7        and the operating and maintenance cost quote will be
8        reimbursed through Coal Development Bonds.
9        (5) Re-powering and retrofitting coal-fired power
10    plants previously owned by Illinois utilities to qualify as
11    clean coal facilities. During the 2009 procurement
12    planning process and thereafter, the Agency and the
13    Commission shall consider sourcing agreements covering
14    electricity generated by power plants that were previously
15    owned by Illinois utilities and that have been or will be
16    converted into clean coal facilities, as defined by Section
17    1-10 of this Act. Pursuant to such procurement planning
18    process, the owners of such facilities may propose to the
19    Agency sourcing agreements with utilities and alternative
20    retail electric suppliers required to comply with
21    subsection (d) of this Section and item (5) of subsection
22    (d) of Section 16-115 of the Public Utilities Act, covering
23    electricity generated by such facilities. In the case of
24    sourcing agreements that are power purchase agreements,
25    the contract price for electricity sales shall be
26    established on a cost of service basis. In the case of

 

 

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1    sourcing agreements that are contracts for differences,
2    the contract price from which the reference price is
3    subtracted shall be established on a cost of service basis.
4    The Agency and the Commission may approve any such utility
5    sourcing agreements that do not exceed cost-based
6    benchmarks developed by the procurement administrator, in
7    consultation with the Commission staff, Agency staff and
8    the procurement monitor, subject to Commission review and
9    approval. The Commission shall have authority to inspect
10    all books and records associated with these clean coal
11    facilities during the term of any such contract.
12        (6) Costs incurred under this subsection (d) or
13    pursuant to a contract entered into under this subsection
14    (d) shall be deemed prudently incurred and reasonable in
15    amount and the electric utility shall be entitled to full
16    cost recovery pursuant to the tariffs filed with the
17    Commission.
18    (d-5) Zero emission standard.
19        (1) Beginning with the delivery year commencing on June
20    1, 2017, the Agency shall, for electric utilities that
21    serve at least 100,000 retail customers in this State,
22    procure contracts with zero emission facilities that are
23    reasonably capable of generating cost-effective zero
24    emission credits in an amount approximately equal to 16% of
25    the actual amount of electricity delivered by each electric
26    utility to retail customers in the State during calendar

 

 

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1    year 2014. For an electric utility serving fewer than
2    100,000 retail customers in this State that requested,
3    under Section 16-111.5 of the Public Utilities Act, that
4    the Agency procure power and energy for all or a portion of
5    the utility's Illinois load for the delivery year
6    commencing June 1, 2016, the Agency shall procure contracts
7    with zero emission facilities that are reasonably capable
8    of generating cost-effective zero emission credits in an
9    amount approximately equal to 16% of the portion of power
10    and energy to be procured by the Agency for the utility.
11    The duration of the contracts procured under this
12    subsection (d-5) shall be for a term of 10 years ending May
13    31, 2027. The quantity of zero emission credits to be
14    procured under the contracts shall be all of the zero
15    emission credits generated by the zero emission facility in
16    each delivery year; however, if the zero emission facility
17    is owned by more than one entity, then the quantity of zero
18    emission credits to be procured under the contracts shall
19    be the amount of zero emission credits that are generated
20    from the portion of the zero emission facility that is
21    owned by the winning supplier.
22        The 16% value identified in this paragraph (1) is the
23    average of the percentage targets in subparagraph (B) of
24    paragraph (1) of subsection (c) of this Section 1-75 of
25    this Act for the 5 delivery years beginning June 1, 2017.
26        The procurement process shall be subject to the

 

 

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1    following provisions:
2            (A) Those zero emission facilities that intend to
3        participate in the procurement shall submit to the
4        Agency the following eligibility information for each
5        zero emission facility on or before the date
6        established by the Agency:
7                (i) the in-service date and remaining useful
8            life of the zero emission facility;
9                (ii) the amount of power generated annually
10            for each of the years 2005 through 2015, and the
11            projected zero emission credits to be generated
12            over the remaining useful life of the zero emission
13            facility, which shall be used to determine the
14            capability of each facility;
15                (iii) the annual zero emission facility cost
16            projections, expressed on a per megawatthour
17            basis, over the next 6 delivery years, which shall
18            include the following: operation and maintenance
19            expenses; fully allocated overhead costs, which
20            shall be allocated using the methodology developed
21            by the Institute for Nuclear Power Operations;
22            fuel expenditures; non-fuel capital expenditures;
23            spent fuel expenditures; a return on working
24            capital; the cost of operational and market risks
25            that could be avoided by ceasing operation; and any
26            other costs necessary for continued operations,

 

 

HB2966- 130 -LRB101 09482 JRG 54580 b

1            provided that "necessary" means, for purposes of
2            this item (iii), that the costs could reasonably be
3            avoided only by ceasing operations of the zero
4            emission facility; and
5                (iv) a commitment to continue operating, for
6            the duration of the contract or contracts executed
7            under the procurement held under this subsection
8            (d-5), the zero emission facility that produces
9            the zero emission credits to be procured in the
10            procurement.
11            The information described in item (iii) of this
12        subparagraph (A) may be submitted on a confidential
13        basis and shall be treated and maintained by the
14        Agency, the procurement administrator, and the
15        Commission as confidential and proprietary and exempt
16        from disclosure under subparagraphs (a) and (g) of
17        paragraph (1) of Section 7 of the Freedom of
18        Information Act. The Office of Attorney General shall
19        have access to, and maintain the confidentiality of,
20        such information pursuant to Section 6.5 of the
21        Attorney General Act.
22            (B) The price for each zero emission credit
23        procured under this subsection (d-5) for each delivery
24        year shall be in an amount that equals the Social Cost
25        of Carbon, expressed on a price per megawatthour basis.
26        However, to ensure that the procurement remains

 

 

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1        affordable to retail customers in this State if
2        electricity prices increase, the price in an
3        applicable delivery year shall be reduced below the
4        Social Cost of Carbon by the amount ("Price
5        Adjustment") by which the market price index for the
6        applicable delivery year exceeds the baseline market
7        price index for the consecutive 12-month period ending
8        May 31, 2016. If the Price Adjustment is greater than
9        or equal to the Social Cost of Carbon in an applicable
10        delivery year, then no payments shall be due in that
11        delivery year. The components of this calculation are
12        defined as follows:
13                (i) Social Cost of Carbon: The Social Cost of
14            Carbon is $16.50 per megawatthour, which is based
15            on the U.S. Interagency Working Group on Social
16            Cost of Carbon's price in the August 2016 Technical
17            Update using a 3% discount rate, adjusted for
18            inflation for each year of the program. Beginning
19            with the delivery year commencing June 1, 2023, the
20            price per megawatthour shall increase by $1 per
21            megawatthour, and continue to increase by an
22            additional $1 per megawatthour each delivery year
23            thereafter.
24                (ii) Baseline market price index: The baseline
25            market price index for the consecutive 12-month
26            period ending May 31, 2016 is $31.40 per

 

 

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1            megawatthour, which is based on the sum of (aa) the
2            average day-ahead energy price across all hours of
3            such 12-month period at the PJM Interconnection
4            LLC Northern Illinois Hub, (bb) 50% multiplied by
5            the Base Residual Auction, or its successor,
6            capacity price for the rest of the RTO zone group
7            determined by PJM Interconnection LLC, divided by
8            24 hours per day, and (cc) 50% multiplied by the
9            Planning Resource Auction, or its successor,
10            capacity price for Zone 4 determined by the
11            Midcontinent Independent System Operator, Inc.,
12            divided by 24 hours per day.
13                (iii) Market price index: The market price
14            index for a delivery year shall be the sum of
15            projected energy prices and projected capacity
16            prices determined as follows:
17                    (aa) Projected energy prices: the
18                projected energy prices for the applicable
19                delivery year shall be calculated once for the
20                year using the forward market price for the PJM
21                Interconnection, LLC Northern Illinois Hub.
22                The forward market price shall be calculated as
23                follows: the energy forward prices for each
24                month of the applicable delivery year averaged
25                for each trade date during the calendar year
26                immediately preceding that delivery year to

 

 

HB2966- 133 -LRB101 09482 JRG 54580 b

1                produce a single energy forward price for the
2                delivery year. The forward market price
3                calculation shall use data published by the
4                Intercontinental Exchange, or its successor.
5                    (bb) Projected capacity prices:
6                        (I) For the delivery years commencing
7                    June 1, 2017, June 1, 2018, and June 1,
8                    2019, the projected capacity price shall
9                    be equal to the sum of (1) 50% multiplied
10                    by the Base Residual Auction, or its
11                    successor, price for the rest of the RTO
12                    zone group as determined by PJM
13                    Interconnection LLC, divided by 24 hours
14                    per day and, (2) 50% multiplied by the
15                    resource auction price determined in the
16                    resource auction administered by the
17                    Midcontinent Independent System Operator,
18                    Inc., in which the largest percentage of
19                    load cleared for Local Resource Zone 4,
20                    divided by 24 hours per day, and where such
21                    price is determined by the Midcontinent
22                    Independent System Operator, Inc.
23                        (II) For the delivery year commencing
24                    June 1, 2020, and each year thereafter, the
25                    projected capacity price shall be equal to
26                    the sum of (1) 50% multiplied by the Base

 

 

HB2966- 134 -LRB101 09482 JRG 54580 b

1                    Residual Auction, or its successor, price
2                    for the ComEd zone as determined by PJM
3                    Interconnection LLC, divided by 24 hours
4                    per day, and (2) 50% multiplied by the
5                    resource auction price determined in the
6                    resource auction administered by the
7                    Midcontinent Independent System Operator,
8                    Inc., in which the largest percentage of
9                    load cleared for Local Resource Zone 4,
10                    divided by 24 hours per day, and where such
11                    price is determined by the Midcontinent
12                    Independent System Operator, Inc.
13            For purposes of this subsection (d-5):
14                "Rest of the RTO" and "ComEd Zone" shall have
15            the meaning ascribed to them by PJM
16            Interconnection, LLC.
17                "RTO" means regional transmission
18            organization.
19            (C) No later than 45 days after June 1, 2017 (the
20        effective date of Public Act 99-906), the Agency shall
21        publish its proposed zero emission standard
22        procurement plan. The plan shall be consistent with the
23        provisions of this paragraph (1) and shall provide that
24        winning bids shall be selected based on public interest
25        criteria that include, but are not limited to,
26        minimizing carbon dioxide emissions that result from

 

 

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1        electricity consumed in Illinois and minimizing sulfur
2        dioxide, nitrogen oxide, and particulate matter
3        emissions that adversely affect the citizens of this
4        State. In particular, the selection of winning bids
5        shall take into account the incremental environmental
6        benefits resulting from the procurement, such as any
7        existing environmental benefits that are preserved by
8        the procurements held under Public Act 99-906 and would
9        cease to exist if the procurements were not held,
10        including the preservation of zero emission
11        facilities. The plan shall also describe in detail how
12        each public interest factor shall be considered and
13        weighted in the bid selection process to ensure that
14        the public interest criteria are applied to the
15        procurement and given full effect.
16            For purposes of developing the plan, the Agency
17        shall consider any reports issued by a State agency,
18        board, or commission under House Resolution 1146 of the
19        98th General Assembly and paragraph (4) of subsection
20        (d) of this Section 1-75 of this Act, as well as
21        publicly available analyses and studies performed by
22        or for regional transmission organizations that serve
23        the State and their independent market monitors.
24            Upon publishing of the zero emission standard
25        procurement plan, copies of the plan shall be posted
26        and made publicly available on the Agency's website.

 

 

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1        All interested parties shall have 10 days following the
2        date of posting to provide comment to the Agency on the
3        plan. All comments shall be posted to the Agency's
4        website. Following the end of the comment period, but
5        no more than 60 days later than June 1, 2017 (the
6        effective date of Public Act 99-906), the Agency shall
7        revise the plan as necessary based on the comments
8        received and file its zero emission standard
9        procurement plan with the Commission.
10            If the Commission determines that the plan will
11        result in the procurement of cost-effective zero
12        emission credits, then the Commission shall, after
13        notice and hearing, but no later than 45 days after the
14        Agency filed the plan, approve the plan or approve with
15        modification. For purposes of this subsection (d-5),
16        "cost effective" means the projected costs of
17        procuring zero emission credits from zero emission
18        facilities do not cause the limit stated in paragraph
19        (2) of this subsection to be exceeded.
20            (C-5) As part of the Commission's review and
21        acceptance or rejection of the procurement results,
22        the Commission shall, in its public notice of
23        successful bidders:
24                (i) identify how the winning bids satisfy the
25            public interest criteria described in subparagraph
26            (C) of this paragraph (1) of minimizing carbon

 

 

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1            dioxide emissions that result from electricity
2            consumed in Illinois and minimizing sulfur
3            dioxide, nitrogen oxide, and particulate matter
4            emissions that adversely affect the citizens of
5            this State;
6                (ii) specifically address how the selection of
7            winning bids takes into account the incremental
8            environmental benefits resulting from the
9            procurement, including any existing environmental
10            benefits that are preserved by the procurements
11            held under Public Act 99-906 and would have ceased
12            to exist if the procurements had not been held,
13            such as the preservation of zero emission
14            facilities;
15                (iii) quantify the environmental benefit of
16            preserving the resources identified in item (ii)
17            of this subparagraph (C-5), including the
18            following:
19                    (aa) the value of avoided greenhouse gas
20                emissions measured as the product of the zero
21                emission facilities' output over the contract
22                term multiplied by the U.S. Environmental
23                Protection Agency eGrid subregion carbon
24                dioxide emission rate and the U.S. Interagency
25                Working Group on Social Cost of Carbon's price
26                in the August 2016 Technical Update using a 3%

 

 

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1                discount rate, adjusted for inflation for each
2                delivery year; and
3                    (bb) the costs of replacement with other
4                zero carbon dioxide resources, including wind
5                and photovoltaic, based upon the simple
6                average of the following:
7                        (I) the price, or if there is more than
8                    one price, the average of the prices, paid
9                    for renewable energy credits from new
10                    utility-scale wind projects in the
11                    procurement events specified in item (i)
12                    of subparagraph (G) of paragraph (1) of
13                    subsection (c) of this Section 1-75 of this
14                    Act; and
15                        (II) the price, or if there is more
16                    than one price, the average of the prices,
17                    paid for renewable energy credits from new
18                    utility-scale solar projects and
19                    brownfield site photovoltaic projects in
20                    the procurement events specified in item
21                    (ii) of subparagraph (G) of paragraph (1)
22                    of subsection (c) of this Section 1-75 of
23                    this Act and, after January 1, 2015,
24                    renewable energy credits from photovoltaic
25                    distributed generation projects in
26                    procurement events held under subsection

 

 

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1                    (c) of this Section 1-75 of this Act.
2            Each utility shall enter into binding contractual
3        arrangements with the winning suppliers.
4            The procurement described in this subsection
5        (d-5), including, but not limited to, the execution of
6        all contracts procured, shall be completed no later
7        than May 10, 2017. Based on the effective date of
8        Public Act 99-906, the Agency and Commission may, as
9        appropriate, modify the various dates and timelines
10        under this subparagraph and subparagraphs (C) and (D)
11        of this paragraph (1). The procurement and plan
12        approval processes required by this subsection (d-5)
13        shall be conducted in conjunction with the procurement
14        and plan approval processes required by subsection (c)
15        of this Section and Section 16-111.5 of the Public
16        Utilities Act, to the extent practicable.
17        Notwithstanding whether a procurement event is
18        conducted under Section 16-111.5 of the Public
19        Utilities Act, the Agency shall immediately initiate a
20        procurement process on June 1, 2017 (the effective date
21        of Public Act 99-906).
22            (D) Following the procurement event described in
23        this paragraph (1) and consistent with subparagraph
24        (B) of this paragraph (1), the Agency shall calculate
25        the payments to be made under each contract for the
26        next delivery year based on the market price index for

 

 

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1        that delivery year. The Agency shall publish the
2        payment calculations no later than May 25, 2017 and
3        every May 25 thereafter.
4            (E) Notwithstanding the requirements of this
5        subsection (d-5), the contracts executed under this
6        subsection (d-5) shall provide that the zero emission
7        facility may, as applicable, suspend or terminate
8        performance under the contracts in the following
9        instances:
10                (i) A zero emission facility shall be excused
11            from its performance under the contract for any
12            cause beyond the control of the resource,
13            including, but not restricted to, acts of God,
14            flood, drought, earthquake, storm, fire,
15            lightning, epidemic, war, riot, civil disturbance
16            or disobedience, labor dispute, labor or material
17            shortage, sabotage, acts of public enemy,
18            explosions, orders, regulations or restrictions
19            imposed by governmental, military, or lawfully
20            established civilian authorities, which, in any of
21            the foregoing cases, by exercise of commercially
22            reasonable efforts the zero emission facility
23            could not reasonably have been expected to avoid,
24            and which, by the exercise of commercially
25            reasonable efforts, it has been unable to
26            overcome. In such event, the zero emission

 

 

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1            facility shall be excused from performance for the
2            duration of the event, including, but not limited
3            to, delivery of zero emission credits, and no
4            payment shall be due to the zero emission facility
5            during the duration of the event.
6                (ii) A zero emission facility shall be
7            permitted to terminate the contract if legislation
8            is enacted into law by the General Assembly that
9            imposes or authorizes a new tax, special
10            assessment, or fee on the generation of
11            electricity, the ownership or leasehold of a
12            generating unit, or the privilege or occupation of
13            such generation, ownership, or leasehold of
14            generation units by a zero emission facility.
15            However, the provisions of this item (ii) do not
16            apply to any generally applicable tax, special
17            assessment or fee, or requirements imposed by
18            federal law.
19                (iii) A zero emission facility shall be
20            permitted to terminate the contract in the event
21            that the resource requires capital expenditures in
22            excess of $40,000,000 that were neither known nor
23            reasonably foreseeable at the time it executed the
24            contract and that a prudent owner or operator of
25            such resource would not undertake.
26                (iv) A zero emission facility shall be

 

 

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1            permitted to terminate the contract in the event
2            the Nuclear Regulatory Commission terminates the
3            resource's license.
4            (F) If the zero emission facility elects to
5        terminate a contract under this subparagraph (E) , of
6        this paragraph (1), then the Commission shall reopen
7        the docket in which the Commission approved the zero
8        emission standard procurement plan under subparagraph
9        (C) of this paragraph (1) and, after notice and
10        hearing, enter an order acknowledging the contract
11        termination election if such termination is consistent
12        with the provisions of this subsection (d-5).
13        (2) For purposes of this subsection (d-5), the amount
14    paid per kilowatthour means the total amount paid for
15    electric service expressed on a per kilowatthour basis. For
16    purposes of this subsection (d-5), the total amount paid
17    for electric service includes, without limitation, amounts
18    paid for supply, transmission, distribution, surcharges,
19    and add-on taxes.
20        Notwithstanding the requirements of this subsection
21    (d-5), the contracts executed under this subsection (d-5)
22    shall provide that the total of zero emission credits
23    procured under a procurement plan shall be subject to the
24    limitations of this paragraph (2). For each delivery year,
25    the contractual volume receiving payments in such year
26    shall be reduced for all retail customers based on the

 

 

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1    amount necessary to limit the net increase that delivery
2    year to the costs of those credits included in the amounts
3    paid by eligible retail customers in connection with
4    electric service to no more than 1.65% of the amount paid
5    per kilowatthour by eligible retail customers during the
6    year ending May 31, 2009. The result of this computation
7    shall apply to and reduce the procurement for all retail
8    customers, and all those customers shall pay the same
9    single, uniform cents per kilowatthour charge under
10    subsection (k) of Section 16-108 of the Public Utilities
11    Act. To arrive at a maximum dollar amount of zero emission
12    credits to be paid for the particular delivery year, the
13    resulting per kilowatthour amount shall be applied to the
14    actual amount of kilowatthours of electricity delivered by
15    the electric utility in the delivery year immediately prior
16    to the procurement, to all retail customers in its service
17    territory. Unpaid contractual volume for any delivery year
18    shall be paid in any subsequent delivery year in which such
19    payments can be made without exceeding the amount specified
20    in this paragraph (2). The calculations required by this
21    paragraph (2) shall be made only once for each procurement
22    plan year. Once the determination as to the amount of zero
23    emission credits to be paid is made based on the
24    calculations set forth in this paragraph (2), no subsequent
25    rate impact determinations shall be made and no adjustments
26    to those contract amounts shall be allowed. All costs

 

 

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1    incurred under those contracts and in implementing this
2    subsection (d-5) shall be recovered by the electric utility
3    as provided in this Section.
4        No later than June 30, 2019, the Commission shall
5    review the limitation on the amount of zero emission
6    credits procured under this subsection (d-5) and report to
7    the General Assembly its findings as to whether that
8    limitation unduly constrains the procurement of
9    cost-effective zero emission credits.
10        (3) Six years after the execution of a contract under
11    this subsection (d-5), the Agency shall determine whether
12    the actual zero emission credit payments received by the
13    supplier over the 6-year period exceed the Average ZEC
14    Payment. In addition, at the end of the term of a contract
15    executed under this subsection (d-5), or at the time, if
16    any, a zero emission facility's contract is terminated
17    under subparagraph (E) of paragraph (1) of this subsection
18    (d-5), then the Agency shall determine whether the actual
19    zero emission credit payments received by the supplier over
20    the term of the contract exceed the Average ZEC Payment,
21    after taking into account any amounts previously credited
22    back to the utility under this paragraph (3). If the Agency
23    determines that the actual zero emission credit payments
24    received by the supplier over the relevant period exceed
25    the Average ZEC Payment, then the supplier shall credit the
26    difference back to the utility. The amount of the credit

 

 

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1    shall be remitted to the applicable electric utility no
2    later than 120 days after the Agency's determination, which
3    the utility shall reflect as a credit on its retail
4    customer bills as soon as practicable; however, the credit
5    remitted to the utility shall not exceed the total amount
6    of payments received by the facility under its contract.
7        For purposes of this Section, the Average ZEC Payment
8    shall be calculated by multiplying the quantity of zero
9    emission credits delivered under the contract times the
10    average contract price. The average contract price shall be
11    determined by subtracting the amount calculated under
12    subparagraph (B) of this paragraph (3) from the amount
13    calculated under subparagraph (A) of this paragraph (3), as
14    follows:
15            (A) The average of the Social Cost of Carbon, as
16        defined in subparagraph (B) of paragraph (1) of this
17        subsection (d-5), during the term of the contract.
18            (B) The average of the market price indices, as
19        defined in subparagraph (B) of paragraph (1) of this
20        subsection (d-5), during the term of the contract,
21        minus the baseline market price index, as defined in
22        subparagraph (B) of paragraph (1) of this subsection
23        (d-5).
24        If the subtraction yields a negative number, then the
25    Average ZEC Payment shall be zero.
26        (4) Cost-effective zero emission credits procured from

 

 

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1    zero emission facilities shall satisfy the applicable
2    definitions set forth in Section 1-10 of this Act.
3        (5) The electric utility shall retire all zero emission
4    credits used to comply with the requirements of this
5    subsection (d-5).
6        (6) Electric utilities shall be entitled to recover all
7    of the costs associated with the procurement of zero
8    emission credits through an automatic adjustment clause
9    tariff in accordance with subsection (k) and (m) of Section
10    16-108 of the Public Utilities Act, and the contracts
11    executed under this subsection (d-5) shall provide that the
12    utilities' payment obligations under such contracts shall
13    be reduced if an adjustment is required under subsection
14    (m) of Section 16-108 of the Public Utilities Act.
15        (7) This subsection (d-5) shall become inoperative on
16    January 1, 2028.
17    (e) The draft procurement plans are subject to public
18comment, as required by Section 16-111.5 of the Public
19Utilities Act.
20    (f) The Agency shall submit the final procurement plan to
21the Commission. The Agency shall revise a procurement plan if
22the Commission determines that it does not meet the standards
23set forth in Section 16-111.5 of the Public Utilities Act.
24    (g) The Agency shall assess fees to each affected utility
25to recover the costs incurred in preparation of the annual
26procurement plan for the utility.

 

 

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1    (h) The Agency shall assess fees to each bidder to recover
2the costs incurred in connection with a competitive procurement
3process.
4    (i) A renewable energy credit, carbon emission credit, or
5zero emission credit can only be used once to comply with a
6single portfolio or other standard as set forth in subsection
7(c), subsection (d), or subsection (d-5) of this Section,
8respectively. A renewable energy credit, carbon emission
9credit, or zero emission credit cannot be used to satisfy the
10requirements of more than one standard. If more than one type
11of credit is issued for the same megawatt hour of energy, only
12one credit can be used to satisfy the requirements of a single
13standard. After such use, the credit must be retired together
14with any other credits issued for the same megawatt hour of
15energy.
16(Source: P.A. 99-536, eff. 7-8-16; 99-906, eff. 6-1-17;
17100-863, eff. 8-14-18; revised 10-18-18.)
 
18    Section 20. The Public Utilities Act is amended by changing
19Sections 16-107.5, 16-107.6, 16-108, and 16-111.5 and by adding
20Section 16-107.7 as follows:
 
21    (220 ILCS 5/16-107.5)
22    Sec. 16-107.5. Net electricity metering.
23    (a) The Legislature finds and declares that a program to
24provide net electricity metering, as defined in this Section,

 

 

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1for eligible customers can encourage private investment in
2renewable energy resources, stimulate economic growth, enhance
3the continued diversification of Illinois' energy resource
4mix, and protect the Illinois environment. Further, to achieve
5the goal of this Act that robust options for customer-site
6distributed generation continue to thrive in Illinois, the
7General Assembly finds that a smooth, predictable transition
8must be ensured for customers between full net metering at the
9retail electricity rate to the distribution generation rebate
10described in Section 16-107.6.
11    (b) As used in this Section, (i) "community renewable
12generation project" shall have the meaning set forth in Section
131-10 of the Illinois Power Agency Act; (ii) "eligible customer"
14means a retail customer that owns, hosts, or operates,
15including any third-party owned systems, a solar, wind, or
16other eligible renewable electrical generating facility with a
17rated capacity of not more than 2,000 kilowatts that is located
18on the customer's premises and is intended primarily to offset
19the customer's own current or future electrical requirements;
20(iii) "electricity provider" means an electric utility or
21alternative retail electric supplier; (iv) "eligible renewable
22electrical generating facility" means a generator, which may
23include the co-location of an energy storage system, that is
24interconnected under rules adopted by the Commission and is
25powered by solar electric energy, wind, dedicated crops grown
26for electricity generation, agricultural residues, untreated

 

 

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1and unadulterated wood waste, landscape trimmings, livestock
2manure, anaerobic digestion of livestock or food processing
3waste, fuel cells or microturbines powered by renewable fuels,
4or hydroelectric energy; (v) "net electricity metering" (or
5"net metering") means the measurement, during the billing
6period applicable to an eligible customer, of the net amount of
7electricity supplied by an electricity provider to the
8customer's premises or provided to the electricity provider by
9the customer or subscriber; (vi) "subscriber" shall have the
10meaning as set forth in Section 1-10 of the Illinois Power
11Agency Act; and (vii) "subscription" shall have the meaning set
12forth in Section 1-10 of the Illinois Power Agency Act; and
13(viii) "energy storage system" means commercially available
14technology that is capable of absorbing energy and storing it
15for a period of time for use at a later time, including, but
16not limited to, electrochemical, thermal, and
17electromechanical technologies, and may be interconnected
18behind the customer's meter or interconnected behind its own
19meter.
20    (c) A net metering facility shall be equipped with metering
21equipment that can measure the flow of electricity in both
22directions at the same rate.
23        (1) For eligible customers whose electric service has
24    not been declared competitive pursuant to Section 16-113 of
25    this Act as of July 1, 2011 and whose electric delivery
26    service is provided and measured on a kilowatt-hour basis

 

 

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

 

 

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1    as the local electric utility installs a smart meter, as
2    described by subsection (b) of Section 16-108.5 of this
3    Act, the electricity provider may arrange for the local
4    electric utility or a meter service provider to install and
5    maintain metering equipment capable of measuring the flow
6    of electricity both into and out of the customer's facility
7    at the same rate and ratio, typically through the use of a
8    dual channel meter. If the eligible customer's existing
9    electric revenue meter does not meet this requirement, then
10    the costs of installing such equipment shall be paid for by
11    the customer.
12    (d) An electricity provider shall measure and charge or
13credit for the net electricity supplied to eligible customers
14or provided by eligible customers whose electric service has
15not been declared competitive pursuant to Section 16-113 of
16this Act as of July 1, 2011 and whose electric delivery service
17is provided and measured on a kilowatt-hour basis and electric
18supply service is not provided based on hourly pricing in the
19following manner:
20        (1) If the amount of electricity used by the customer
21    during the billing period exceeds the amount of electricity
22    produced by the customer, the electricity provider shall
23    charge the customer for the net electricity supplied to and
24    used by the customer as provided in subsection (e-5) of
25    this Section.
26        (2) If the amount of electricity produced by a customer

 

 

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

 

 

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1    during any hourly period exceeds the amount of electricity
2    produced by the customer, the electricity provider shall
3    charge the customer for the net electricity supplied to and
4    used by the customer according to the terms of the contract
5    or tariff to which the same customer would be assigned to
6    or be eligible for if the customer was not a net metering
7    customer.
8        (2) If the amount of electricity produced by a customer
9    during any hourly period or time-of-use period exceeds the
10    amount of electricity used by the customer during that
11    hourly period or time-of-use period, the energy provider
12    shall apply a credit for the net kilowatt-hours produced in
13    such period. The credit shall consist of an energy credit
14    and a delivery service credit. The energy credit shall be
15    valued at the same price per kilowatt-hour as the electric
16    service provider would charge for kilowatt-hour energy
17    sales during that same hourly or time-of-use period. The
18    delivery credit shall be equal to the net kilowatt-hours
19    produced in such hourly or time-of-use period times a
20    credit that reflects all kilowatt-hour based charges in the
21    customer's electric service rate, excluding energy
22    charges.
23    (e) An electricity provider shall measure and charge or
24credit for the net electricity supplied to eligible customers
25whose electric service has not been declared competitive
26pursuant to Section 16-113 of this Act as of July 1, 2011 and

 

 

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1whose electric delivery service is provided and measured on a
2kilowatt demand basis and electric supply service is not
3provided based on hourly pricing in the following manner:
4        (1) If the amount of electricity used by the customer
5    during the billing period exceeds the amount of electricity
6    produced by the customer, then the electricity provider
7    shall charge the customer for the net electricity supplied
8    to and used by the customer as provided in subsection (e-5)
9    of this Section. The customer shall remain responsible for
10    all taxes, fees, and utility delivery charges that would
11    otherwise be applicable to the net amount of electricity
12    used by the customer.
13        (2) If the amount of electricity produced by a customer
14    during the billing period exceeds the amount of electricity
15    used by the customer during that billing period, then the
16    electricity provider supplying that customer shall apply a
17    1:1 kilowatt-hour credit that reflects the kilowatt-hour
18    based charges in the customer's electric service rate to a
19    subsequent bill for service to the customer for the net
20    electricity supplied to the electricity provider. The
21    electricity provider shall continue to carry over any
22    excess kilowatt-hour credits earned and apply those
23    credits to subsequent billing periods to offset any
24    customer-generator consumption in those billing periods
25    until all credits are used or until the end of the
26    annualized period.

 

 

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1        (3) At the end of the year or annualized over the
2    period that service is supplied by means of net metering,
3    or in the event that the retail customer terminates service
4    with the electricity provider prior to the end of the year
5    or the annualized period, any remaining credits in the
6    customer's account shall expire.
7    (e-5) An electricity provider shall provide electric
8service to eligible customers who utilize net metering at
9non-discriminatory rates that are identical, with respect to
10rate structure, retail rate components, and any monthly
11charges, to the rates that the customer would be charged if not
12a net metering customer. An electricity provider shall not
13charge net metering customers any fee or charge or require
14additional equipment, insurance, or any other requirements not
15specifically authorized by interconnection standards
16authorized by the Commission, unless the fee, charge, or other
17requirement would apply to other similarly situated customers
18who are not net metering customers. The customer will remain
19responsible for all taxes, fees, and utility delivery charges
20that would otherwise be applicable to the net amount of
21electricity used by the customer. Subsections (c) through (e)
22of this Section shall not be construed to prevent an
23arms-length agreement between an electricity provider and an
24eligible customer that sets forth different prices, terms, and
25conditions for the provision of net metering service,
26including, but not limited to, the provision of the appropriate

 

 

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1metering equipment for non-residential customers.
2    (f) Notwithstanding the requirements of subsections (c)
3through (e-5) of this Section, an electricity provider must
4require dual-channel metering for customers operating eligible
5renewable electrical generating facilities with a nameplate
6rating up to 2,000 kilowatts and to whom the provisions of
7neither subsection (d), (d-5), nor (e) of this Section apply.
8In such cases, electricity charges and credits shall be
9determined as follows:
10        (1) The electricity provider shall assess and the
11    customer remains responsible for all taxes, fees, and
12    utility delivery charges that would otherwise be
13    applicable to the gross amount of kilowatt-hours supplied
14    to the eligible customer by the electricity provider.
15        (2) Each month that service is supplied by means of
16    dual-channel metering, the electricity provider shall
17    compensate the eligible customer for any excess
18    kilowatt-hour credits at the electricity provider's
19    avoided cost of electricity supply over the monthly period
20    or as otherwise specified by the terms of a power-purchase
21    agreement negotiated between the customer and electricity
22    provider.
23        (3) For all eligible net metering customers taking
24    service from an electricity provider under contracts or
25    tariffs employing hourly or time of use rates, any monthly
26    consumption of electricity shall be calculated according

 

 

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1    to the terms of the contract or tariff to which the same
2    customer would be assigned to or be eligible for if the
3    customer was not a net metering customer. When those same
4    customer-generators are net generators during any discrete
5    hourly or time of use period, the net kilowatt-hours
6    produced shall be valued at the same price per
7    kilowatt-hour as the electric service provider would
8    charge for retail kilowatt-hour sales during that same time
9    of use period.
10    (g) For purposes of federal and State laws providing
11renewable energy credits or greenhouse gas credits, the
12eligible customer shall be treated as owning and having title
13to the renewable energy attributes, renewable energy credits,
14and greenhouse gas emission credits related to any electricity
15produced by the qualified generating unit. The electricity
16provider may not condition participation in a net metering
17program on the signing over of a customer's renewable energy
18credits; provided, however, this subsection (g) shall not be
19construed to prevent an arms-length agreement between an
20electricity provider and an eligible customer that sets forth
21the ownership or title of the credits.
22    (h) Within 120 days after the effective date of this
23amendatory Act of the 95th General Assembly, the Commission
24shall establish standards for net metering and, if the
25Commission has not already acted on its own initiative,
26standards for the interconnection of eligible renewable

 

 

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1generating equipment to the utility system. The
2interconnection standards shall address any procedural
3barriers, delays, and administrative costs associated with the
4interconnection of customer-generation while ensuring the
5safety and reliability of the units and the electric utility
6system. The Commission shall consider the Institute of
7Electrical and Electronics Engineers (IEEE) Standard 1547 and
8the issues of (i) reasonable and fair fees and costs, (ii)
9clear timelines for major milestones in the interconnection
10process, (iii) nondiscriminatory terms of agreement, and (iv)
11any best practices for interconnection of distributed
12generation.
13    Within 90 days after the effective date of this amendatory
14Act of the 101st General Assembly, the Commission shall open a
15proceeding to update the interconnection standards and
16applicable utility tariffs. For the public interest, safety,
17and welfare of Illinois citizens, the Commission may adopt
18emergency rules under Section 5-45 of the Illinois
19Administrative Procedure Act to implement this Section. In
20addition to items (i) through (iv) in this subsection (h), the
21Commission shall also revise the standards to address the
22following, including, but not limited to, critical standards
23for interconnection:
24        (i) transparency and accuracy of costs, both direct and
25    indirect, while maintaining system security through the
26    effective management of confidentiality agreements;

 

 

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1        (ii) standardization of typical costs associated with
2    interconnection;
3        (iii) transparency of the interconnection queue or
4    queues and hosting capacity;
5        (iv) development of hosting capacity maps that enable
6    greater visibility to customers about the locations with
7    the greatest need or availability;
8        (v) predictability of the queue management process and
9    enforcement of timelines;
10        (vi) benefits and challenges associated with group
11    studies and cost sharing;
12        (vii) minimum requirements for application to the
13    interconnection process and throughout the interconnection
14    process to avoid queue clogging behavior;
15        (viii) requiring that the electric utility performing
16    the interconnection study justify their interconnection
17    study cost and the estimates of costs for identified
18    upgrades, and to cap payments required by the
19    interconnection customer for the electric utility
20    installed facilities to the lesser of +50% of the
21    Feasibility Study estimate, +25% of the System Impact Study
22    estimate, or +10% of the Facilities Study estimate;
23        (ix) allowing customers to self-supply interconnection
24    studies when the electric utility are unable provide such
25    studies at a reasonable cost and schedule;
26        (x) allowing customers to self-build system upgrades

 

 

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1    consistent with electric utility standards when the
2    electric utility cannot provide such upgrades and
3    interconnection facilities at a reasonable cost and
4    schedule;
5        (xi) preventing the electric utility from adding
6    overheads to their actual and estimated costs for both
7    studies and system upgrades. Provide a mechanism for a
8    customer to review invoices and internal accounting
9    statements to verify costs incurred by the electric
10    utility;
11        (xii) requiring all interconnection agreements to be
12    filed with the Illinois Commerce Commission;
13        (xiii) revising the electric utility reporting
14    requirements to include information regarding ability of
15    utilities to meet timelines established under these
16    interconnection standards and to introduce penalties for
17    utilities that do not meet such requirements, to be
18    commensurate with penalties faced by interconnection
19    customers that fail to meet requirements under these
20    interconnection standards;
21        (xiv) facilitating the deployment of energy storage
22    systems while ensuring the continued grid safety and
23    reliability of the system, including addressing the
24    following:
25            (1) treatment of energy storage systems as
26        generation for purposes of the interconnection,

 

 

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1        ownership and operation;
2            (2) fair study assumptions that reflect the
3        operational profile of the energy storage device;
4            (3) streamlined notification-only interconnection
5        requirements for non-exporting systems that meet
6        utility criteria for safety and reliability, as is
7        determined through a robust stakeholder process; and
8            (4) enabling exports from customer-sited energy
9        storage systems for participation either in utility
10        programs or wholesale markets; and
11        (xv) establishment of a dispute resolution process
12    designed to address instances of unreasonable impediments
13    by an electric utility to the critical standards for
14    interconnection enumerated in subsections (i) - (xiv) of
15    this subsection (h). The Commission will make available
16    adequate Commission Staff for this dispute resolution
17    process to ensure that matters are decided on an expedited
18    basis.
19    As part of this proceeding, the Commission shall establish
20an interconnection working group. The working group shall
21include representatives from electric utilities, developers of
22renewable electric generating facilities, other industries
23that regularly apply for interconnection with the electric
24utilities, representatives of distributed generation
25customers, the Commission staff, and other stakeholders with a
26substantial interest in the topics addressed by the working

 

 

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1group. The working group shall address cost and best available
2technology for interconnection and metering, distribution
3system upgrade cost avoidance through use of advanced inverter
4functions, process and customer service for interconnecting
5customers adopting distributed energy resources, including
6energy storage; options for metering distributed energy
7resources, including energy storage; interconnection of new
8technologies, including smart inverters and energy storage,
9and, without limitation, other technical, policy, and tariff
10issues related to and affecting interconnection performance
11and customer service, as determined by the working group. The
12Commission may create working group subcommittees of the
13working group to focus on specific issues of importance, as
14appropriate. The working group shall report to the Commission
15on recommended improvements to interconnection rules and
16tariffs and such other recommendations as determined by the
17working group, within 6 months of its first meeting, and every
186 months thereafter. Such report shall include consensus
19recommendations of the working group and, if applicable,
20additional recommendations for which consensus was not
21reached. The outcomes of the working group shall inform the
22policies, processes, tariffs, and standards associated with
23interconnection and should create standards and processes that
24support the achievement of the objectives in subparagraph (K)
25of paragraph (1) of subsection (c) of Section 1-75 of the
26Illinois Power Agency Act.

 

 

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1    (i) All electricity providers shall begin to offer net
2metering no later than April 1, 2008.
3    (j) An electricity utility provider shall provide net
4metering to eligible customers until the load of its net
5metering customers equals 5% of the total peak demand delivered
6supplied by that electricity provider during the previous year.
7After such time as the load of the electricity provider's net
8metering customers equals 5% of the total peak demand delivered
9supplied by that electricity utility provider during the
10previous year, and the Commission has approved the distributed
11generation rebate and applicable tariff following
12investigation as set out in subsection (e) of Section 16-107.6
13of this Act, eligible customers that begin taking net metering
14shall only be eligible for netting of energy.
15    (k) Each electricity provider shall maintain records and
16report annually to the Commission the total number of net
17metering customers served by the provider, as well as the type,
18capacity, and energy sources of the generating systems used by
19the net metering customers. Nothing in this Section shall limit
20the ability of an electricity provider to request the redaction
21of information deemed by the Commission to be confidential
22business information.
23    (l)(1) Notwithstanding the definition of "eligible
24customer" in item (ii) of subsection (b) of this Section, each
25electricity provider shall allow net metering as set forth in
26this subsection (l) and for the following projects, provided

 

 

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1that only electric utilities shall provide net metering for
2subparagraph (C) of this paragraph (1):
3        (A) properties owned or leased by multiple customers
4    that contribute to the operation of an eligible renewable
5    electrical generating facility through an ownership or
6    leasehold interest of at least 200 watts in such facility,
7    such as a community-owned wind project, a community-owned
8    biomass project, a community-owned solar project, or a
9    community methane digester processing livestock waste from
10    multiple sources, provided that the facility is also
11    located within the utility's service territory;
12        (B) individual units, apartments, or properties
13    located in a single building that are owned or leased by
14    multiple customers and collectively served by a common
15    eligible renewable electrical generating facility, such as
16    an office or apartment building, a shopping center or strip
17    mall served by photovoltaic panels on the roof; and
18        (C) subscriptions to community renewable generation
19    projects.
20    In addition, the nameplate capacity of the eligible
21renewable electric generating facility that serves the demand
22of the properties, units, or apartments identified in
23paragraphs (1) and (2) of this subsection (l) shall not exceed
242,000 kilowatts in nameplate capacity in total. Any eligible
25renewable electrical generating facility or community
26renewable generation project that is powered by photovoltaic

 

 

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1electric energy and installed after the effective date of this
2amendatory Act of the 99th General Assembly must be installed
3by a qualified person in compliance with the requirements of
4Section 16-128A of the Public Utilities Act and any rules or
5regulations adopted thereunder.
6    (2) Notwithstanding anything to the contrary and
7regardless of whether a subscriber receives power and energy
8service from the electric utility or an alternative retail
9electric supplier, the electric utility , an electricity
10provider shall provide credits for the electricity produced by
11the community renewable generation projects projects described
12in paragraph (1) of this subsection (l). The electric utility
13electricity provider shall provide credits at the utility's
14total price to compare subscriber's energy supply rate on the
15subscriber's monthly bill equal to the subscriber's share of
16the production of electricity from the project, as determined
17by paragraph (3) of this subsection (l). For the purposes of
18this subsection, "total price to compare" means the rate or
19rates published by the Illinois Commerce Commission for energy
20supply for eligible customers receiving supply service from the
21electric utility, and shall include energy, capacity,
22transmission, and the purchased energy adjustment. The credit
23provided by the electric utility shall be adjusted monthly to
24reflect the total price to compare of the applicable month but
25may never result in a credit equal to less than the total price
26to compare as of January 1, 2019. Any applicable credit or

 

 

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1reduction in load obligation from the production of the
2community renewable generating projects receiving a credit
3under this subsection shall be credited to the electric utility
4to offset the cost of providing the credit. To the extent that
5the credit or load obligation reduction does not completely
6offset the cost of providing the credit to subscribers of
7community renewable generation projects as described in this
8subsection the electric utility may recover the remaining costs
9through the process established in Section 16-111.8 of this
10Act.
11    (3) For the purposes of facilitating net metering, the
12owner or operator of the eligible renewable electrical
13generating facility or community renewable generation project
14shall be responsible for determining the amount of the credit
15that each customer or subscriber participating in a project
16under this subsection (l) is to receive in the following
17manner:
18        (A) The owner or operator shall, on a monthly basis,
19    provide to the electric utility the hours kilowatthours of
20    generation attributable to each of the utility's retail
21    customers and subscribers participating in projects under
22    this subsection (l) in accordance with the customer's or
23    subscriber's share of the eligible renewable electric
24    generating facility's or community renewable generation
25    project's output of power and energy for such month. The
26    owner or operator shall electronically transmit such

 

 

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1    calculations and associated documentation to the electric
2    utility, in a format or method set forth in the applicable
3    tariff, on a monthly basis so that the electric utility can
4    reflect the monetary credits on customers' and
5    subscribers' electric utility bills. The electric utility
6    shall be permitted to revise its tariffs to implement the
7    provisions of this amendatory Act of the 101st General
8    Assembly this amendatory Act of the 99th General Assembly.
9    The owner or operator shall separately provide the electric
10    utility with the documentation detailing the calculations
11    supporting the credit in the manner set forth in the
12    applicable tariff.
13        (B) For those participating customers in projects
14    described in subparagraph (A) of this paragraph (3) and
15    subscribers who receive their energy supply from an
16    alternative retail electric supplier, the electric utility
17    shall remit to the applicable alternative retail electric
18    supplier the information provided under subparagraph (A)
19    of this paragraph (3) for such customers and subscribers in
20    a manner set forth in such alternative retail electric
21    supplier's net metering program, or as otherwise agreed
22    between the utility and the alternative retail electric
23    supplier. The alternative retail electric supplier shall
24    then submit to the utility the amount of the charges for
25    power and energy to be applied to such customers and
26    subscribers, including the amount of the credit associated

 

 

HB2966- 168 -LRB101 09482 JRG 54580 b

1    with net metering.
2        (C) A participating customer or subscriber may provide
3    authorization as required by applicable law that directs
4    the electric utility to submit information to the owner or
5    operator of the eligible renewable electrical generating
6    facility or community renewable generation project to
7    which the customer or subscriber has an ownership or
8    leasehold interest or a subscription. Such information
9    shall be limited to the components of the net metering
10    credit calculated under this subsection (l), including the
11    bill credit rate, total kilowatthours, and total monetary
12    credit value applied to the customer's or subscriber's bill
13    for the monthly billing period.
14    (l-5) Within 90 days after the effective date of this
15amendatory Act of the 101st General Assembly this amendatory
16Act of the 99th General Assembly, each electric utility subject
17to this Section shall file a tariff to implement the provisions
18of subsection (l) of this Section, which shall, consistent with
19the provisions of subsection (l), describe the terms and
20conditions under which owners or operators of qualifying
21properties, units, or apartments may participate in net
22metering. The Commission shall approve, or approve with
23modification, the tariff within 120 days after the effective
24date of this amendatory Act of the 101st General Assembly this
25amendatory Act of the 99th General Assembly.
26    (m) Nothing in this Section shall affect the right of an

 

 

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1electricity provider to continue to provide, or the right of a
2retail customer to continue to receive service pursuant to a
3contract for electric service between the electricity provider
4and the retail customer in accordance with the prices, terms,
5and conditions provided for in that contract. Either the
6electricity provider or the customer may require compliance
7with the prices, terms, and conditions of the contract.
8    (n) At such time, if any, that the load of the electricity
9utility's provider's net metering customers equals 5% of the
10total peak demand delivered supplied by that electricity
11utility provider during the previous year, as specified in
12subsection (j) of this Section, and the Commission has approved
13the distributed generation rebate and applicable tariff
14following investigation set out in subsection (e) of Section
1516-107.6 of this Act, the net metering services described in
16subsections (d), (d-5), (e), (e-5), and (f) of this Section
17shall no longer be offered, except as to those retail customers
18that are receiving net metering service under these subsections
19at the time the net metering services under those subsections
20are no longer offered, who shall continue to receive net
21metering services described in subsections (d), (d-5), (e),
22(e-5), and (f) of this Section for the lifetime of the system,
23regardless of whether those retail customers change
24electricity providers. Those retail customers that begin
25taking net metering service after the date that net metering
26services are no longer offered under such subsections shall be

 

 

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1subject to the provisions set forth in the following paragraphs
2(1) through (3) of this subsection (n):
3        (1) An electricity provider shall charge or credit for
4    the net electricity supplied to eligible customers or
5    provided by eligible customers whose electric supply
6    service is not provided based on hourly pricing in the
7    following manner:
8            (A) If the amount of electricity used by the
9        customer during the billing period exceeds the amount
10        of electricity produced by the customer, then the
11        electricity provider shall charge the customer for the
12        net kilowatt-hour based electricity charges reflected
13        in the customer's electric service rate supplied to and
14        used by the customer as provided in paragraph (3) of
15        this subsection (n).
16            (B) If the amount of electricity produced by a
17        customer during the billing period exceeds the amount
18        of electricity used by the customer during that billing
19        period, then the electricity provider supplying that
20        customer shall apply a 1:1 kilowatt-hour energy credit
21        that reflects the kilowatt-hour based energy charges
22        in the customer's electric service rate to a subsequent
23        bill for service to the customer for the net
24        electricity supplied to the electricity provider. The
25        electricity provider shall continue to carry over any
26        excess kilowatt-hour energy credits earned and apply

 

 

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1        those credits to subsequent billing periods to offset
2        any customer-generator consumption in those billing
3        periods until all credits are used or until the end of
4        the annualized period.
5            (C) At the end of the year or annualized over the
6        period that service is supplied by means of net
7        metering, or in the event that the retail customer
8        terminates service with the electricity provider prior
9        to the end of the year or the annualized period, any
10        remaining credits in the customer's account shall
11        expire.
12        (2) An electricity provider shall charge or credit for
13    the net electricity supplied to eligible customers or
14    provided by eligible customers whose electric supply
15    service is provided based on hourly pricing in the
16    following manner:
17            (A) If the amount of electricity used by the
18        customer during any hourly period exceeds the amount of
19        electricity produced by the customer, then the
20        electricity provider shall charge the customer for the
21        net electricity supplied to and used by the customer as
22        provided in paragraph (3) of this subsection (n).
23            (B) If the amount of electricity produced by a
24        customer during any hourly period exceeds the amount of
25        electricity used by the customer during that hourly
26        period, the energy provider shall calculate an energy

 

 

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

 

 

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1    delivery services charges, supply-related charges that are
2    kilowatt based, and all taxes and fees related to such
3    charges. The customer also remains responsible for all
4    taxes and fees that would otherwise be applicable to the
5    net amount of electricity used by the customer. Paragraphs
6    (1) and (2) of this subsection (n) shall not be construed
7    to prevent an arms-length agreement between an electricity
8    provider and an eligible customer that sets forth different
9    prices, terms, and conditions for the provision of net
10    metering service, including, but not limited to, the
11    provision of the appropriate metering equipment for
12    non-residential customers. Nothing in this paragraph (3)
13    shall be interpreted to mandate that a utility that is only
14    required to provide delivery services to a given customer
15    must also sell electricity to such customer.
16    (o) Within 90 days after the effective date of this
17amendatory Act of the 101st General Assembly, each electric
18utility subject to this Section shall file a tariff that shall,
19consistent with the provisions this Section, propose the terms
20and conditions under which an eligible customer may participate
21in net metering. The Commission shall approve, or approve with
22modification based on stakeholder process, the tariff within
23120 days after effective date of this amendatory Act of the
24101st General Assembly. Each electric utility shall file any
25changes to terms as a subsequent tariff for approval or
26approval with modifications from Commission.

 

 

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1(Source: P.A. 99-906, eff. 6-1-17.)
 
2    (220 ILCS 5/16-107.6)
3    Sec. 16-107.6. Distributed generation rebate.
4    (a) In this Section:
5    "Energy storage system" means commercially available
6technology that is capable of absorbing energy and storing it
7for a period of time for use at a later time, including, but
8not limited to, electrochemical, thermal, and
9electromechanical technologies, and may be interconnected
10behind the customer's meter or interconnected behind its own
11meter.
12    "Smart inverter" means a device that converts direct
13current into alternating current and can autonomously
14contribute to grid support during excursions from normal
15operating voltage and frequency conditions by providing each of
16the following: dynamic reactive and real power support, voltage
17and frequency ride-through, ramp rate controls, communication
18systems with ability to accept external commands, and other
19functions from the electric utility as approved by the Illinois
20Commerce Commission.
21    "Subscriber" has the meaning set forth in Section 1-10 of
22the Illinois Power Agency Act.
23    "Subscription" has the meaning set forth in Section 1-10 of
24the Illinois Power Agency Act.
25    "Threshold date" means the date on which the load of an

 

 

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1electricity utility's provider's net metering customers equals
25% of the total peak demand delivered supplied by that
3electricity utility provider during the previous year, as
4specified under subsection (j) of Section 16-107.5 of this Act.
5    (b) An electric utility that serves more than 200,000
6customers in the State shall file a petition with the
7Commission requesting approval of the utility's tariff to
8provide a rebate to a retail customer who owns, hosts, or
9operates distributed generation, including third-party-owned
10systems, that meets the following criteria:
11        (1) has a nameplate generating capacity no greater than
12    2,000 kilowatts and is primarily used to offset that
13    customer's electricity load;
14        (2) is located on the customer's premises, for the
15    customer's own use, and not for commercial use or sales,
16    including, but not limited to, wholesale sales of electric
17    power and energy;
18        (3) is located in the electric utility's service
19    territory; and
20        (4) is interconnected under rules adopted by the
21    Commission by means of the inverter or smart inverter
22    required by this Section, as applicable.
23    For purposes of this Section, "distributed generation"
24shall satisfy the definition of distributed renewable energy
25generation device set forth in Section 1-10 of the Illinois
26Power Agency Act to the extent such definition is consistent

 

 

HB2966- 176 -LRB101 09482 JRG 54580 b

1with the requirements of this Section.
2    In addition, any new photovoltaic distributed generation
3that is installed after the effective date of this amendatory
4Act of the 99th General Assembly must be installed by a
5qualified person, as defined by subsection (i) of Section 1-56
6of the Illinois Power Agency Act.
7    The tariff shall provide that the utility shall be
8permitted to operate and control the smart inverter associated
9with the distributed generation that is the subject of the
10rebate for the purpose of preserving reliability during
11distribution system reliability events and shall address the
12terms and conditions of the operation and the compensation
13associated with the operation. Nothing in this Section shall
14negate or supersede Institute of Electrical and Electronics
15Engineers interconnection requirements or standards or other
16similar standards or requirements. The tariff shall also
17provide for additional uses of the smart inverter that shall be
18optional for the owner of the distributed generation owner to
19activate and, if activated, shall be separately compensated so
20as to mitigate loss of revenue to the owner of the distributed
21generation for production curtailment or diminishment of real
22power output due to the activation of such uses. Such
23additional uses shall and which may include, but are not
24limited to, voltage and VAR support, voltage watt, frequency
25watt, regulation, and other grid services. As part of the
26proceeding described in subsection (e) of this Section, the

 

 

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1Commission shall review and determine whether smart inverters
2can provide any additional uses or services. If the Commission
3determines that an additional use or service would be
4beneficial, the Commission shall determine the terms and
5conditions of the operation and shall approve compensation for
6activation of additional uses in a monetary form. The
7Commission shall also approve the ability of the utility to
8offer compensation to the owner of the distributed generation
9owner in the form of reduced project-specific interconnection
10upgrades, and the owner of the distributed generation may
11choose either the monetary compensation or the reduction in
12interconnection upgrades and how the use or service should be
13separately compensated.
14    (c) The proposed tariff authorized by subsection (b) of
15this Section shall include the following participation terms
16and formulae to calculate the value of the rebates to be
17applied under this Section for distributed generation that
18satisfies the criteria set forth in subsection (b) of this
19Section:
20        (1) Until the utility files its tariff or tariffs to
21    place into effect the rebate values established by the
22    Commission under subsection (e) of this Section,
23    non-residential customers that are taking service under a
24    net metering program offered by an electricity provider
25    under the terms of Section 16-107.5 of this Act may apply
26    for a rebate as provided for in this Section. The value of

 

 

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1    the rebate shall be $250 per kilowatt of nameplate
2    generating capacity, measured as nominal DC power output,
3    of a non-residential customer's distributed generation. To
4    the extent the distributed generation system also has a
5    storage device as part of the system, and said storage uses
6    the same smart inverter as the distributed generation, then
7    the storage shall be separately compensated at $350 per
8    kilowatt of nameplate capacity. Energy storage nameplate
9    capacity means the kilowatt-hour of rated AC capacity of
10    the installed system.
11        (2) After the utility's tariff or tariffs setting the
12    new rebate values established under subsection (d) of this
13    Section take effect, retail customers may, as applicable,
14    make the following elections:
15            (A) Residential customers that are taking service
16        under a net metering program offered by an electricity
17        provider under the terms of Section 16-107.5 of this
18        Act on the threshold date may elect to either continue
19        to take such service under the terms of such program as
20        in effect on such threshold date for the useful life of
21        the customer's eligible renewable electric generating
22        facility as defined in such Section, or file an
23        application to receive a rebate under the terms of this
24        Section, provided that such application must be
25        submitted within 6 months after the effective date of
26        the tariff approved under subsection (d) of this

 

 

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

 

 

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1    subsection (c), customers who begin taking service after
2    the effective date of this amendatory Act of the 99th
3    General Assembly under a net metering program offered by an
4    electricity provider under the terms of Section 16-107.5 of
5    this Act must have a smart inverter associated with the
6    customer's distributed generation.
7    (d) The Commission shall review the proposed tariff
8submitted under subsections (b) and (c) of this Section and may
9make changes to the tariff that are consistent with this
10Section and with the Commission's authority under Article IX of
11this Act, subject to notice and hearing. Following notice and
12hearing, the Commission shall issue an order approving, or
13approving with modification, such tariff no later than 240 days
14after the utility files its tariff.
15    (e) When the total generating capacity of the electricity
16utility's provider's net metering customers is equal to 3% of
17the total peak demand delivered by that utility, the Commission
18shall open an investigation into a an annual process and
19formula for calculating the value of rebates for the retail
20customers described in subsections (b) and (f) of this Section
21that submit rebate applications after the threshold date for an
22electric utility that elected to file a tariff pursuant to this
23Section. The process and formula for calculating the value of
24the rebate available after the threshold date shall be updated
25every 5 years, and shall promote continuity in the distributed
26generation market. The investigation shall include diverse

 

 

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1sets of stakeholders, calculations for valuing distributed
2energy resource benefits to the grid based on best practices,
3and assessments of present and future technological
4capabilities of distributed energy resources. The value of such
5rebates shall reflect the value of the distributed generation
6to the distribution system at the location at which it is
7interconnected, taking into account the geographic,
8time-based, and performance-based benefits, as well as
9technological capabilities and present and future grid needs.
10No later than 10 days after the Commission enters its final
11order under this subsection (e), the utility shall file its
12tariff or tariffs in compliance with the order, and the
13Commission shall approve, or approve with modification, the
14tariff or tariffs within 45 days after the utility's filing.
15For those rebate applications filed after the threshold date
16but before the utility's tariff or tariffs filed pursuant to
17this subsection (e) take effect, the value of the rebate shall
18remain at the value established in subsection (c) of this
19Section until the tariff is approved.
20    (f) Notwithstanding any provision of this Act to the
21contrary, the owner, developer, or subscriber of a generation
22facility that is part of a net metering program provided under
23subsection (l) of Section 16-107.5 shall also be eligible to
24apply for the rebate described in this Section. A subscriber to
25the generation facility may apply for a rebate in the amount of
26the subscriber's subscription only if the owner, developer, or

 

 

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

 

 

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1but not limited to, the value of the rebates and all costs
2incurred by the utility to comply with and implement this
3Section, consistent with the following provisions:
4        (1) The utility shall defer the full amount of its
5    costs incurred under this Section as a regulatory asset.
6    The total costs deferred as a regulatory asset shall be
7    amortized over a 15-year period. The unamortized balance
8    shall be recognized as of December 31 for a given year. The
9    utility shall also earn a return on the total of the
10    unamortized balance of the regulatory assets, less any
11    deferred taxes related to the unamortized balance, at an
12    annual rate equal to the utility's weighted average cost of
13    capital that includes, based on a year-end capital
14    structure, the utility's actual cost of debt for the
15    applicable calendar year and a cost of equity, which shall
16    be calculated as the sum of (i) the average for the
17    applicable calendar year of the monthly average yields of
18    30-year U.S. Treasury bonds published by the Board of
19    Governors of the Federal Reserve System in its weekly H.15
20    Statistical Release or successor publication; and (ii) 580
21    basis points, including a revenue conversion factor
22    calculated to recover or refund all additional income taxes
23    that may be payable or receivable as a result of that
24    return.
25        When an electric utility creates a regulatory asset
26    under the provisions of this Section, the costs are

 

 

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1    recovered over a period during which customers also receive
2    a benefit, which is in the public interest. Accordingly, it
3    is the intent of the General Assembly that an electric
4    utility that elects to create a regulatory asset under the
5    provisions of this Section shall recover all of the
6    associated costs, including, but not limited to, its cost
7    of capital as set forth in this Section. After the
8    Commission has approved the prudence and reasonableness of
9    the costs that comprise the regulatory asset, the electric
10    utility shall be permitted to recover all such costs, and
11    the value and recoverability through rates of the
12    associated regulatory asset shall not be limited, altered,
13    impaired, or reduced. To enable the financing of the
14    incremental capital expenditures, including regulatory
15    assets, for electric utilities that serve less than
16    3,000,000 retail customers but more than 500,000 retail
17    customers in the State, the utility's actual year-end
18    capital structure that includes a common equity ratio,
19    excluding goodwill, of up to and including 50% of the total
20    capital structure shall be deemed reasonable and used to
21    set rates.
22        (2) The utility, at its election, may recover all of
23    the costs it incurs under this Section as part of a filing
24    for a general increase in rates under Article IX of this
25    Act, as part of an annual filing to update a
26    performance-based formula rate under subsection (d) of

 

 

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1    Section 16-108.5 of this Act, or through an automatic
2    adjustment clause tariff, provided that nothing in this
3    paragraph (2) permits the double recovery of such costs
4    from customers. If the utility elects to recover the costs
5    it incurs under this Section through an automatic
6    adjustment clause tariff, the utility may file its proposed
7    tariff together with the tariff it files under subsection
8    (b) of this Section or at a later time. The proposed tariff
9    shall provide for an annual reconciliation, less any
10    deferred taxes related to the reconciliation, with
11    interest at an annual rate of return equal to the utility's
12    weighted average cost of capital as calculated under
13    paragraph (1) of this subsection (h), including a revenue
14    conversion factor calculated to recover or refund all
15    additional income taxes that may be payable or receivable
16    as a result of that return, of the revenue requirement
17    reflected in rates for each calendar year, beginning with
18    the calendar year in which the utility files its automatic
19    adjustment clause tariff under this subsection (h), with
20    what the revenue requirement would have been had the actual
21    cost information for the applicable calendar year been
22    available at the filing date. The Commission shall review
23    the proposed tariff and may make changes to the tariff that
24    are consistent with this Section and with the Commission's
25    authority under Article IX of this Act, subject to notice
26    and hearing. Following notice and hearing, the Commission

 

 

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

 

 

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

 

 

HB2966- 188 -LRB101 09482 JRG 54580 b

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

 

 

HB2966- 189 -LRB101 09482 JRG 54580 b

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

 

 

HB2966- 190 -LRB101 09482 JRG 54580 b

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

 

 

HB2966- 191 -LRB101 09482 JRG 54580 b

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

 

 

HB2966- 192 -LRB101 09482 JRG 54580 b

1            including customer-connected,
2            distribution-connected, and
3            transmission-connected;
4                (iii) adopting requirements or processes by
5            the Illinois Power Agency for competitive
6            deployment of energy storage services from third
7            parties; and
8                (iv) appropriate accountability mechanisms.
9        (3) By December 31, 2019, the findings and
10    recommendations for the programs, policies, and funding
11    levels to meet the energy storage deployment targets from
12    this study shall be submitted to the General Assembly and
13    the Governor for consideration and appropriate action.
14    The Illinois Power Agency shall include a plan to procure
15energy from energy storage resources pursuant to the results of
16this study as part of its Procurement Plan for 2021. An
17electric utility shall file tariffs directed by the Commission
18to recover from its retail customers the costs associated with
19the procurement of energy storage under this Section.
 
20    (220 ILCS 5/16-108)
21    Sec. 16-108. Recovery of costs associated with the
22provision of delivery and other services.
23    (a) An electric utility shall file a delivery services
24tariff with the Commission at least 210 days prior to the date
25that it is required to begin offering such services pursuant to

 

 

HB2966- 193 -LRB101 09482 JRG 54580 b

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

 

 

HB2966- 194 -LRB101 09482 JRG 54580 b

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

 

 

HB2966- 195 -LRB101 09482 JRG 54580 b

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

 

 

HB2966- 196 -LRB101 09482 JRG 54580 b

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

 

 

HB2966- 197 -LRB101 09482 JRG 54580 b

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

 

 

HB2966- 198 -LRB101 09482 JRG 54580 b

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