Rep. Robert Rita

Filed: 3/20/2015

 

 


 

 


 
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1
AMENDMENT TO HOUSE BILL 3328

2    AMENDMENT NO. ______. Amend House Bill 3328 by replacing
3everything after the enacting clause with the following:
 
4    "Section 5. The Illinois Power Agency Act is amended by
5changing Sections 1-10, 1-56, and 1-75 as follows:
 
6    (20 ILCS 3855/1-10)
7    Sec. 1-10. Definitions.
8    "Agency" means the Illinois Power Agency.
9    "Agency loan agreement" means any agreement pursuant to
10which the Illinois Finance Authority agrees to loan the
11proceeds of revenue bonds issued with respect to a project to
12the Agency upon terms providing for loan repayment installments
13at least sufficient to pay when due all principal of, interest
14and premium, if any, on those revenue bonds, and providing for
15maintenance, insurance, and other matters in respect of the
16project.

 

 

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1    "Authority" means the Illinois Finance Authority.
2    "Brownfield site project" means photovoltaics located at a
3site that is:
4        (1) located in an area that, on April 5, 2004, was in
5    non-attainment for the National Ambient Air Quality
6    Standard 1997 PM2.5 Standard;
7        (2) interconnected at the distribution system level of
8    either an electric utility as defined in this Section, a
9    municipal utility, or an electric cooperative as defined in
10    Section 3-119 of the Public Utilities Act; and
11        (3) regulated by any of the following entities under
12    the following programs:
13            (i) the United States Environmental Protection
14        Agency under the federal Comprehensive Environmental
15        Response, Compensation, and Liability Act of 1980, as
16        amended;
17            (ii) the United States Environmental Protection
18        Agency under the Corrective Action Program of the
19        federal Resource Conservation and Recovery Act, as
20        amended; or
21            (iii) the Illinois Environmental Protection Agency
22        under the Illinois Site Remediation Program.
23    "Clean coal facility" means an electric generating
24facility that uses primarily coal as a feedstock and that
25captures and sequesters carbon dioxide emissions at the
26following levels: at least 50% of the total carbon dioxide

 

 

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1emissions that the facility would otherwise emit if, at the
2time construction commences, the facility is scheduled to
3commence operation before 2016, at least 70% of the total
4carbon dioxide emissions that the facility would otherwise emit
5if, at the time construction commences, the facility is
6scheduled to commence operation during 2016 or 2017, and at
7least 90% of the total carbon dioxide emissions that the
8facility would otherwise emit if, at the time construction
9commences, the facility is scheduled to commence operation
10after 2017. The power block of the clean coal facility shall
11not exceed allowable emission rates for sulfur dioxide,
12nitrogen oxides, carbon monoxide, particulates and mercury for
13a natural gas-fired combined-cycle facility the same size as
14and in the same location as the clean coal facility at the time
15the clean coal facility obtains an approved air permit. All
16coal used by a clean coal facility shall have high volatile
17bituminous rank and greater than 1.7 pounds of sulfur per
18million btu content, unless the clean coal facility does not
19use gasification technology and was operating as a conventional
20coal-fired electric generating facility on June 1, 2009 (the
21effective date of Public Act 95-1027).
22    "Clean coal SNG brownfield facility" means a facility that
23(1) has commenced construction by July 1, 2015 on an urban
24brownfield site in a municipality with at least 1,000,000
25residents; (2) uses a gasification process to produce
26substitute natural gas; (3) uses coal as at least 50% of the

 

 

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

 

 

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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    "Department" means the Department of Commerce and Economic

 

 

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1Opportunity.
2    "Director" means the Director of the Illinois Power Agency.
3    "Demand-response" means measures that decrease peak
4electricity demand or shift demand from peak to off-peak
5periods.
6    "Distributed renewable energy generation device" means a
7device that is:
8        (1) powered by wind, solar thermal energy,
9    photovoltaic cells and panels, biodiesel, crops and
10    untreated and unadulterated organic waste biomass, tree
11    waste, and hydropower that does not involve new
12    construction or significant expansion of hydropower dams;
13        (2) interconnected at the distribution system level of
14    either an electric utility as defined in this Section, an
15    alternative retail electric supplier as defined in Section
16    16-102 of the Public Utilities Act, a municipal utility as
17    defined in Section 3-105 of the Public Utilities Act, or a
18    rural electric cooperative as defined in Section 3-119 of
19    the Public Utilities Act;
20        (3) located on the customer side of the customer's
21    electric meter and is primarily used to offset that
22    customer's electricity load; and
23        (4) limited in nameplate capacity to no more than 2,000
24    kilowatts.
25    "Energy efficiency" means measures that reduce the amount
26of electricity or natural gas required to achieve a given end

 

 

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1use. "Energy efficiency" includes voltage optimization
2measures, which are measures that optimize the voltage at
3points on the electric distribution voltage system to conserve
4energy consumption by electric customers. "Energy efficiency"
5also includes measures that reduce the total Btus of
6electricity, and natural gas, and other fuels needed to meet
7the end use or uses.
8    "Electric utility" has the same definition as found in
9Section 16-102 of the Public Utilities Act.
10    "Facility" means an electric generating unit or a
11co-generating unit that produces electricity along with
12related equipment necessary to connect the facility to an
13electric transmission or distribution system.
14    "Governmental aggregator" means one or more units of local
15government that individually or collectively procure
16electricity to serve residential retail electrical loads
17located within its or their jurisdiction.
18    "Local government" means a unit of local government as
19defined in Section 1 of Article VII of the Illinois
20Constitution.
21    "Municipality" means a city, village, or incorporated
22town.
23    "Person" means any natural person, firm, partnership,
24corporation, either domestic or foreign, company, association,
25limited liability company, joint stock company, or association
26and includes any trustee, receiver, assignee, or personal

 

 

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1representative thereof.
2    "Project" means the planning, bidding, and construction of
3a facility.
4    "Public utility" has the same definition as found in
5Section 3-105 of the Public Utilities Act.
6    "Real property" means any interest in land together with
7all structures, fixtures, and improvements thereon, including
8lands under water and riparian rights, any easements,
9covenants, licenses, leases, rights-of-way, uses, and other
10interests, together with any liens, judgments, mortgages, or
11other claims or security interests related to real property.
12    "Renewable energy credit" means a tradable credit that
13represents the environmental attributes of a certain amount of
14energy produced from a renewable energy resource.
15    "Renewable energy resources" includes energy and its
16associated renewable energy credit or renewable energy credits
17from wind, solar thermal energy, photovoltaic cells and panels,
18biodiesel, anaerobic digestion, crops and untreated and
19unadulterated organic waste biomass, tree waste, hydropower
20that does not involve new construction or significant expansion
21of hydropower dams, and other alternative sources of
22environmentally preferable energy. For purposes of this Act,
23landfill gas produced in the State is considered a renewable
24energy resource. "Renewable energy resources" does not include
25the incineration or burning of tires, garbage, general
26household, institutional, and commercial waste, industrial

 

 

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1lunchroom or office waste, landscape waste other than tree
2waste, railroad crossties, utility poles, or construction or
3demolition debris, other than untreated and unadulterated
4waste wood.
5    "Revenue bond" means any bond, note, or other evidence of
6indebtedness issued by the Authority, the principal and
7interest of which is payable solely from revenues or income
8derived from any project or activity of the Agency.
9    "Sequester" means permanent storage of carbon dioxide by
10injecting it into a saline aquifer, a depleted gas reservoir,
11or an oil reservoir, directly or through an enhanced oil
12recovery process that may involve intermediate storage,
13regardless of whether these activities are conducted by a clean
14coal facility, a clean coal SNG facility, a clean coal SNG
15brownfield facility, or a party with which a clean coal
16facility, clean coal SNG facility, or clean coal SNG brownfield
17facility has contracted for such purposes.
18    "Sourcing agreement" means (i) in the case of an electric
19utility, an agreement between the owner of a clean coal
20facility and such electric utility, which agreement shall have
21terms and conditions meeting the requirements of paragraph (3)
22of subsection (d) of Section 1-75, (ii) in the case of an
23alternative retail electric supplier, an agreement between the
24owner of a clean coal facility and such alternative retail
25electric supplier, which agreement shall have terms and
26conditions meeting the requirements of Section 16-115(d)(5) of

 

 

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1the Public Utilities Act, and (iii) in case of a gas utility,
2an agreement between the owner of a clean coal SNG brownfield
3facility and the gas utility, which agreement shall have the
4terms and conditions meeting the requirements of subsection
5(h-1) of Section 9-220 of the Public Utilities Act.
6    "Substitute natural gas" or "SNG" means a gas manufactured
7by gasification of hydrocarbon feedstock, which is
8substantially interchangeable in use and distribution with
9conventional natural gas.
10    "Total resource cost test" or "TRC test" means a standard
11that is met if, for an investment in energy efficiency or
12demand-response measures, the benefit-cost ratio is greater
13than one. The benefit-cost ratio is the ratio of the net
14present value of the total benefits of the program to the net
15present value of the total costs as calculated over the
16lifetime of the measures. A total resource cost test compares
17the sum of avoided electric utility costs, representing the
18benefits that accrue to the system and the participant in the
19delivery of those efficiency measures, as well as other
20quantifiable societal benefits, including avoided natural gas
21utility costs associated with natural gas or other fuels, to
22the sum of all incremental costs of end-use measures that are
23implemented due to the program (including both utility and
24participant contributions), plus costs to administer, deliver,
25and evaluate each demand-side program, to quantify the net
26savings obtained by substituting the demand-side program for

 

 

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1supply resources. In calculating avoided costs of power and
2energy that an electric utility would otherwise have had to
3acquire, reasonable estimates shall be included of financial
4costs likely to be imposed by future regulations and
5legislation on emissions of greenhouse gases. Notwithstanding
6anything to the contrary, the benefits identified in this
7definition shall only be included in the TRC test if they are
8measurable and quantifiable, and the TRC test shall not include
9or take into account a calculation of market price suppression
10effects or demand reduction induced price effects. The changes
11made to this definition by this amendatory Act of the 99th
12General Assembly are intended to be a restatement and
13clarification of existing law.
14(Source: P.A. 97-96, eff. 7-13-11; 97-239, eff. 8-2-11; 97-491,
15eff. 8-22-11; 97-616, eff. 10-26-11; 97-813, eff. 7-13-12;
1698-90, eff. 7-15-13.)
 
17    (20 ILCS 3855/1-56)
18    Sec. 1-56. Illinois Power Agency Renewable Energy
19Resources Fund.
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 to procure renewable
24energy credits resources. Renewable energy credits Prior to
25June 1, 2011, resources procured pursuant to this Section shall

 

 

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1be procured from facilities located in Illinois, provided the
2resources are available from those facilities. If resources are
3not available in Illinois, then they shall be procured in
4states that adjoin Illinois. If resources are not available in
5Illinois or in states that adjoin Illinois, then they may be
6purchased elsewhere. Beginning June 1, 2011, resources
7procured pursuant to this Section shall be procured from
8facilities located in Illinois or states that adjoin Illinois.
9If renewable energy credits resources are not available in
10Illinois or in states that adjoin Illinois, then they may be
11procured elsewhere. To the extent available, at least 75% of
12these renewable energy credits resources shall come from wind
13generation. Of the renewable energy credits resources procured
14pursuant to this Section at least the following specified
15percentages shall come from photovoltaics on the following
16schedule: 0.5% by June 1, 2012; 1.5% by June 1, 2013; 3% by
17June 1, 2014; and 6% by June 1, 2015 and thereafter. Of the
18renewable energy credits resources procured pursuant to this
19Section, at least the following percentages shall come from
20distributed renewable energy generation devices: 0.5% by June
211, 2013, 0.75% by June 1, 2014, and 1% by June 1, 2015 and
22thereafter. To the extent available, half of the renewable
23energy credits resources procured from distributed renewable
24energy generation shall come from devices of less than 25
25kilowatts in nameplate capacity. Renewable energy credits
26resources procured from distributed generation devices may

 

 

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1also count towards the required percentages for wind and solar
2photovoltaics. Procurement of renewable energy credits
3resources from distributed renewable energy generation devices
4shall be done on an annual basis through multi-year contracts
5of no less than 5 years, and shall consist solely of renewable
6energy credits. Of the renewable energy credits from
7photovoltaics that are not distributed renewable energy
8generation devices procured pursuant to this Section, at least
9one-half shall come from brownfield site projects, if
10available. The Agency shall create application requirements
11for brownfield site projects that shall include, as
12appropriate, credit requirements for suppliers, demonstrated
13site control, bid bond requirements, construction completion
14deadlines, or other appropriate conditions to ensure
15confidence that selected bids will result in successful
16projects. Beginning June 1, 2018, each renewable energy
17resources plan shall specify how the moneys available in the
18Illinois Power Agency Renewable Energy Resources Fund for a
19given planning year shall be allocated to satisfy the
20photovoltaic requirements of this subsection (b) and
21subsection (j) of this Section.
22    The Agency shall create credit requirements for suppliers
23of distributed renewable energy. In order to minimize the
24administrative burden on contracting entities, the Agency
25shall solicit the use of third-party organizations to aggregate
26distributed renewable energy into groups of no less than one

 

 

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1megawatt in installed capacity. These third-party
2organizations shall administer contracts with individual
3distributed renewable energy generation device owners. An
4individual distributed renewable energy generation device
5owner shall have the ability to measure the output of his or
6her distributed renewable energy generation device.
7    (c) Pursuant to a renewable energy resources plan approved
8by the Commission under Section 16-111.5 of the Public
9Utilities Act, the The Agency shall procure renewable energy
10credits using moneys in the Illinois Power Agency Renewable
11Energy Resources Fund or moneys projected to be deposited into
12the Fund resources at least once each year in conjunction with
13a procurement event for electric utilities required to comply
14with Section 1-75 of the Act and shall, whenever possible,
15enter into long-term contracts on an annual basis for a portion
16of the incremental requirement for the given procurement year.
17Plans for the procurement of renewable energy credits through
18long-term contracts shall recognize the possible impacts of
19customer migration between alternative retail electric
20suppliers and electric utility electric supply service and
21shall be designed to limit the potential that eligible retail
22customers may be required to pay for curtailed credits in
23excess of those required to meet the minimum for attainment of
24the goals set forth in paragraph (1) of subsection (c) of
25Section 1-75 of this Act.
26    In the event of any curtailment required in order to comply

 

 

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1with the rate impact limits of paragraph (2) of subsection (c)
2of Section 1-75 of this Act with respect to a contract for
3purchase of certain renewable energy resources held by an
4electric utility, as single credits or in a bundle with other
5credits or other resources, the Agency shall offer to purchase
6from the supplier any renewable energy credits associated with
7such renewable energy resources that would have been purchased
8by the electric utility but for the curtailment; however, the
9offer shall not include renewable energy credits that have been
10purchased by any other means. Purchases of curtailed renewable
11energy credits by the Agency shall be made at (i) the contract
12price for each renewable energy credit if a price is explicitly
13stated in the original contract or (ii) the imputed price of
14the renewable energy credit, if purchased under a bundled
15contract and where no price for a renewable energy credit is
16explicitly stated in the original bundled contract, as
17determined by the Agency and approved by the Commission.
18Purchases of curtailed renewable energy credits shall be made
19using moneys from the Illinois Power Agency Renewable Energy
20Resources Fund. The Agency's use of moneys from the Illinois
21Power Agency Renewable Energy Resources Fund shall not exceed
22the total amount of moneys on deposit in the Fund or projected
23to be deposited into the Fund. Except as provided in this
24subsection (c), the Agency's purchase of renewable energy
25credits pursuant to a curtailment shall be made in accordance
26with all other terms of the original contract between the

 

 

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1supplier and the electric utility and shall not include an
2obligation for physical deliveries of electricity. The Agency
3shall not purchase, nor enter into contracts for, any other
4renewable energy resources using moneys in the Illinois Power
5Agency Renewable Energy Resources Fund, unless either (i) all
6of the renewable energy credits subject to curtailment have
7been contracted for purchase or (ii) the supplier has declined
8the Agency's offer to purchase the renewable energy credits
9subject to curtailment.
10    (d) The price paid to procure renewable energy credits
11using monies from the Illinois Power Agency Renewable Energy
12Resources Fund shall not exceed market-based benchmarks
13established by the procurement administrator in consultation
14with the Commission staff, Agency staff, and the procurement
15monitor the winning bid prices paid for like resources procured
16for electric utilities required to comply with Section 1-75 of
17this Act. This subsection (d) does not apply to purchases of
18curtailed renewable energy credits made pursuant to the second
19paragraph of subsection (c) of this Section.
20    (e) All renewable energy credits procured using monies from
21the Illinois Power Agency Renewable Energy Resources Fund shall
22be permanently retired.
23    (f) The procurement process described in this Section is
24exempt from the requirements of the Illinois Procurement Code,
25pursuant to Section 20-10 of that Code.
26    (g) All disbursements from the Illinois Power Agency

 

 

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

 

 

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

 

 

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1    hands-on electrical experience: (i) a North American Board
2    of Certified Energy Practitioners (NABCEP) Installer
3    Certificate for Solar PV; (ii) an Underwriters
4    Laboratories (UL) PV Systems Installer Certificate; (iii)
5    an Electronics Technicians Association, International
6    (ETAI) Level 3 PV Installer Certificate; or (iv) an
7    Associate in Applied Science degree from an Illinois
8    Community College Board approved community college program
9    in renewable energy or a distributed generation
10    technology.
11        For the purposes of this paragraph (1), "directly
12    supervised" means that there is a qualified person who
13    meets the qualifications under clause (A) of this paragraph
14    (1) and who is available for supervision and consultation
15    regarding the work performed by persons under clause (B) of
16    this paragraph (1), including a final inspection of the
17    installation work that has been directly supervised to
18    ensure safety and conformity with applicable codes.
19        For the purposes of this paragraph (1), "install" means
20    the major activities and actions required to connect, in
21    accordance with applicable building and electrical codes,
22    the conductors, connectors, and all associated fittings,
23    devices, power outlets, or apparatuses mounted at the
24    premises that are directly involved in delivering energy to
25    the premises' electrical wiring from the photovoltaics,
26    including, but not limited to, to distributed photovoltaic

 

 

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

 

 

09900HB3328ham001- 21 -LRB099 10473 MLM 33016 a

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

 

 

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

 

 

09900HB3328ham001- 23 -LRB099 10473 MLM 33016 a

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

 

 

09900HB3328ham001- 24 -LRB099 10473 MLM 33016 a

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

 

 

09900HB3328ham001- 25 -LRB099 10473 MLM 33016 a

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

 

 

09900HB3328ham001- 26 -LRB099 10473 MLM 33016 a

1        bidders must agree to the terms of the contract in
2        advance so that winning bids are selected solely on the
3        basis of price.
4            (E) Requests for proposals; competitive
5        procurement process. The procurement administrator
6        shall design and issue requests for proposals to supply
7        renewable energy credits in accordance with the
8        supplemental procurement plan, as approved by the
9        Commission. The requests for proposals shall set forth
10        a procedure for sealed, binding commitment bidding
11        with pay-as-bid settlement, and provision for
12        selection of bids on the basis of price, provided,
13        however, that no bid shall be accepted if it exceeds
14        the benchmark developed pursuant to item (F) of this
15        paragraph (4).
16            (F) Benchmarks. Benchmarks for each product to be
17        procured shall be developed by the procurement
18        administrator in consultation with Commission staff,
19        the Agency, and the procurement monitor for use in this
20        supplemental procurement.
21            (G) A plan for implementing contingencies in the
22        event of supplier default, Commission rejection of
23        results, or any other cause.
24        (5) Within 2 business days after opening the sealed
25    bids, the procurement administrator shall submit a
26    confidential report to the Commission. The report shall

 

 

09900HB3328ham001- 27 -LRB099 10473 MLM 33016 a

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

 

 

09900HB3328ham001- 28 -LRB099 10473 MLM 33016 a

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

 

 

09900HB3328ham001- 29 -LRB099 10473 MLM 33016 a

1    supplemental procurement process.
2    (j) Beginning June 1, 2018, the moneys available in the
3Illinois Power Agency Renewable Energy Resources Fund for a
4given planning year that are not required to be used for
5purchasing (i) the minimum amounts of renewable energy credits
6specified in subsection (b) of this Section, other than credits
7from photovoltaics, and (ii) curtailed credits pursuant to
8subsection (c) of this Section, shall be used to purchase
9renewable energy credits from photovoltaic projects as
10specified in this subsection (j) and subsection (b) of this
11Section and for other photovoltaic project costs as described
12in this subsection (j). Of the amount available for
13photovoltaic projects described in this subsection (j), at
14least one-half shall be used for low-income community
15photovoltaic projects approved by the Agency, to the extent
16available. The Agency shall specify in each renewable energy
17resources plan how the moneys available in the Illinois Power
18Agency Renewable Energy Resources Fund for a given planning
19year shall be allocated to satisfy the photovoltaic
20requirements of this subsection (j) and subsection (b) of this
21Section.
22    Consistent with the provisions of this subsection (j), the
23administrative costs incurred by the Agency and electric
24utilities associated with the photovoltaic projects and
25procurement pursuant to this subsection (j) shall be recovered
26from the Illinois Power Agency Renewable Energy Resources Fund.

 

 

09900HB3328ham001- 30 -LRB099 10473 MLM 33016 a

1The Agency shall maintain a reserve of 10% of the moneys
2available in the Illinois Power Agency Renewable Energy
3Resources Fund to ensure the payment of these administrative
4costs. Electric utilities shall submit invoices to the Agency
5for reimbursement of the costs the utilities incur under this
6subsection (j) associated with photovoltaic projects and
7community photovoltaic projects, including low-income
8community photovoltaic projects, and the Agency shall
9reimburse the utilities using moneys from the Illinois Power
10Agency Renewable Energy Resources Fund within 30 days. Such
11costs shall include, but are not limited to, the costs the
12utility incurs to bill participants of photovoltaic projects.
13The administrative costs that the Agency may incur shall
14include third-party administrator and aggregator costs and
15such other administrative costs that the Agency deems (and the
16Commission finds) appropriate to initiate, administer,
17install, and operate community photovoltaic projects,
18including low-income community photovoltaic projects. The
19Agency shall establish an application process and eligibility
20criteria applicable to the approval of community photovoltaic
21projects. The criteria shall be consistent with the criteria
22set forth in subsection (j) of Section 16-107.6 of the Public
23Utilities Act, and include, but not be limited to, a maximum
24nameplate capacity of 2 megawatts per project, a minimum
25participant share requirement of 2 kilowatts, and a requirement
26that the participant's address at which it receives electric

 

 

09900HB3328ham001- 31 -LRB099 10473 MLM 33016 a

1service from the electric utility shall be located within 5
2miles of the location of the community photovoltaic project,
3provided that such project is also located within the utility's
4service territory. No project approved pursuant to this
5subsection (j) shall require an electric utility to exceed the
6limitations imposed by subsection (h) of Section 16-107.6 of
7the Public Utilities Act.
8    The Agency shall have authority to retain, by contract,
9such administrators as are necessary and appropriate to
10initiate, administer, aggregate, operate, maintain, and
11evaluate community photovoltaic projects that are otherwise
12consistent with the provisions of this Section. Such
13administrators shall be retained in the same manner, to the
14extent reasonably practicable, as the Agency retains others to
15administer provisions of this Act including, but not limited
16to, the procurement administrator. The Agency shall undertake
17to retain the necessary administrators for at least 2
18low-income community photovoltaic projects by January 1, 2018.
19    If the moneys available in the Illinois Power Agency
20Renewable Energy Resources Fund are not sufficient to reimburse
21the electric utility for its costs as provided by this
22subsection (j) or the Agency fails to reimburse the utility for
23such costs within 30 days, the utility may recover such costs
24from its retail customers through a filing made pursuant to
25Article IX or Section 16-108.5 of the Public Utilities Act.
26(Source: P.A. 97-616, eff. 10-26-11; 98-672, eff. 6-30-14.)
 

 

 

09900HB3328ham001- 32 -LRB099 10473 MLM 33016 a

1    (20 ILCS 3855/1-75)
2    Sec. 1-75. Planning and Procurement Bureau. The Planning
3and Procurement Bureau has the following duties and
4responsibilities:
5    (a) The Planning and Procurement Bureau shall each year,
6beginning in 2008, develop procurement plans and conduct
7competitive procurement processes in accordance with the
8requirements of Section 16-111.5 of the Public Utilities Act
9for the eligible retail customers of electric utilities that on
10December 31, 2005 provided electric service to at least 100,000
11customers in Illinois. The Planning and Procurement Bureau
12shall also develop procurement plans and conduct competitive
13procurement processes in accordance with the requirements of
14Section 16-111.5 of the Public Utilities Act for the eligible
15retail customers of small multi-jurisdictional electric
16utilities that (i) on December 31, 2005 served less than
17100,000 customers in Illinois and (ii) request a procurement
18plan for their Illinois jurisdictional load. This Section shall
19not apply to a small multi-jurisdictional utility until such
20time as a small multi-jurisdictional utility requests the
21Agency to prepare a procurement plan for their Illinois
22jurisdictional load. For the purposes of this Section, the term
23"eligible retail customers" has the same definition as found in
24Section 16-111.5(a) of the Public Utilities Act.
25        (1) The Agency shall each year, beginning in 2008, as

 

 

09900HB3328ham001- 33 -LRB099 10473 MLM 33016 a

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

 

 

09900HB3328ham001- 34 -LRB099 10473 MLM 33016 a

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

 

 

09900HB3328ham001- 35 -LRB099 10473 MLM 33016 a

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

 

 

09900HB3328ham001- 36 -LRB099 10473 MLM 33016 a

1    as procurement administrator.
2        (5) The Agency shall select an expert or expert
3    consulting firm to develop procurement plans based on the
4    proposals submitted and shall award contracts of up to 5
5    years to those selected.
6        (6) The Agency shall select an expert or expert
7    consulting firm, with approval of the Commission, to serve
8    as procurement administrator based on the proposals
9    submitted. If the Commission rejects, within 5 days, the
10    Agency's selection, the Agency shall submit another
11    recommendation within 3 days based on the proposals
12    submitted. The Agency shall award a 5-year contract to the
13    expert or expert consulting firm so selected with
14    Commission approval.
15    (b) The experts or expert consulting firms retained by the
16Agency shall, as appropriate, prepare procurement plans, and
17conduct a competitive procurement process as prescribed in
18Section 16-111.5 of the Public Utilities Act, to ensure
19adequate, reliable, affordable, efficient, and environmentally
20sustainable electric service at the lowest total cost over
21time, taking into account any benefits of price stability, for
22eligible retail customers of electric utilities that on
23December 31, 2005 provided electric service to at least 100,000
24customers in the State of Illinois, and for eligible Illinois
25retail customers of small multi-jurisdictional electric
26utilities that (i) on December 31, 2005 served less than

 

 

09900HB3328ham001- 37 -LRB099 10473 MLM 33016 a

1100,000 customers in Illinois and (ii) request a procurement
2plan for their Illinois jurisdictional load.
3    (c) Renewable portfolio standard.
4        (1) The procurement plans shall include cost-effective
5    renewable energy resources. A minimum percentage of each
6    utility's total supply to serve the load of eligible retail
7    customers, as defined in Section 16-111.5(a) of the Public
8    Utilities Act, procured for each of the following years
9    shall be generated from cost-effective renewable energy
10    resources: at least 2% by June 1, 2008; at least 4% by June
11    1, 2009; at least 5% by June 1, 2010; at least 6% by June 1,
12    2011; at least 7% by June 1, 2012; at least 8% by June 1,
13    2013; at least 9% by June 1, 2014; at least 10% by June 1,
14    2015; and increasing by at least 1.5% each year thereafter
15    to at least 25% by June 1, 2025. To the extent that it is
16    available, at least 75% of the renewable energy resources
17    used to meet these standards shall come from wind
18    generation and, beginning on June 1, 2011, at least the
19    following percentages of the renewable energy resources
20    used to meet these standards shall come from photovoltaics
21    on the following schedule: 0.5% by June 1, 2012, 1.5% by
22    June 1, 2013; 3% by June 1, 2014; and 6% by June 1, 2015 and
23    thereafter. Of the renewable energy resources procured
24    pursuant to this Section, at least the following
25    percentages shall come from distributed renewable energy
26    generation devices: 0.5% by June 1, 2013, 0.75% by June 1,

 

 

09900HB3328ham001- 38 -LRB099 10473 MLM 33016 a

1    2014, and 1% by June 1, 2015 and thereafter. To the extent
2    available, half of the renewable energy resources procured
3    from distributed renewable energy generation shall come
4    from devices of less than 25 kilowatts in nameplate
5    capacity. Renewable energy resources procured from
6    distributed generation devices may also count towards the
7    required percentages for wind and solar photovoltaics.
8    Procurement of renewable energy resources from distributed
9    renewable energy generation devices shall be done on an
10    annual basis through multi-year contracts of no less than 5
11    years, and shall consist solely of renewable energy
12    credits. Of the renewable energy resources from
13    photovoltaics that are not distributed renewable energy
14    generation devices procured pursuant to this Section, at
15    least one-half shall come from brownfield site projects, if
16    available. The Agency shall create application
17    requirements for brownfield site projects that shall
18    include, as appropriate, credit requirements for
19    suppliers, demonstrated site control, bid bond
20    requirements, construction completion deadlines, or other
21    appropriate conditions to ensure confidence that selected
22    bids will result in successful projects.
23        The Agency shall create credit requirements for
24    suppliers of distributed renewable energy. In order to
25    minimize the administrative burden on contracting
26    entities, the Agency shall solicit the use of third-party

 

 

09900HB3328ham001- 39 -LRB099 10473 MLM 33016 a

1    organizations to aggregate distributed renewable energy
2    into groups of no less than one megawatt in installed
3    capacity. These third-party organizations shall administer
4    contracts with individual distributed renewable energy
5    generation device owners. An individual distributed
6    renewable energy generation device owner shall have the
7    ability to measure the output of his or her distributed
8    renewable energy generation device.
9        For purposes of this subsection (c), "cost-effective"
10    means that the costs of procuring renewable energy
11    resources do not cause the limit stated in paragraph (2) of
12    this subsection (c) to be exceeded and do not exceed
13    benchmarks based on market prices for renewable energy
14    resources in the region, which shall be developed by the
15    procurement administrator, in consultation with the
16    Commission staff, Agency staff, and the procurement
17    monitor and shall be subject to Commission review and
18    approval.
19        (1.5) If, as a result of customer migration between
20    alternative retail electric suppliers and electric utility
21    electric supply service, the Agency has insufficient
22    moneys available in the Illinois Power Agency Renewable
23    Energy Resources Fund to cover the contract cost of
24    renewable energy credits procured pursuant to Section 1-56
25    of this Act, the Commission, pursuant to an approved
26    renewable energy resources plan, shall direct the

 

 

09900HB3328ham001- 40 -LRB099 10473 MLM 33016 a

1    applicable utility to offer to purchase those renewable
2    energy credits that (i) are assigned to its service
3    territory pursuant to a Commission-approved renewable
4    energy resources plan; (ii) the Agency is unable to
5    purchase due to insufficient moneys available in the
6    Illinois Power Agency Renewable Energy Resources Fund as a
7    consequence of such customer migration; and (iii) are
8    subject to curtailment; however, such direction to offer to
9    purchase such renewable energy credits shall in no event
10    include renewable energy credits that have been purchased
11    by any other means. Any curtailed renewable energy credits
12    purchased by the assigned electric utility in accordance
13    with this provision shall count toward the minimum
14    percentages of renewable energy resources required by this
15    Section. Nothing in this Section shall require a supplier
16    to sell its renewable energy credits in this manner.
17        Purchases of curtailed renewable energy credits
18    originally contracted for by the Agency shall be made at
19    the contract price for each renewable energy credit. Except
20    as provided in this subsection (c), an electric utility's
21    purchase of curtailed renewable energy credits shall be
22    made in accordance with all other terms of the original
23    contract between the supplier and the Agency and shall not
24    include an obligation for physical deliveries of
25    electricity. An electric utility shall not purchase, nor
26    enter into contracts for, any other renewable energy

 

 

09900HB3328ham001- 41 -LRB099 10473 MLM 33016 a

1    resources pursuant to this subsection (c), unless either
2    (i) all of the renewable energy credits subject to
3    curtailment have been contracted for purchase or (ii) the
4    supplier has declined the applicable utility's offer to
5    purchase the renewable energy credits subject to
6    curtailment. Nothing in this paragraph alters the
7    limitations imposed by paragraph (2) of this subsection (c)
8    or requires renewable energy credit purchases in excess of
9    the amount required to meet the renewable goals set forth
10    in this subsection (c).
11        (2) For purposes of this subsection (c), the required
12    procurement of cost-effective renewable energy resources
13    for a particular year shall be measured as a percentage of
14    the actual amount of electricity (megawatt-hours) supplied
15    by the electric utility to eligible retail customers in the
16    planning year ending immediately prior to the procurement.
17    For purposes of this subsection (c), the amount paid per
18    kilowatthour means the total amount paid for electric
19    service expressed on a per kilowatthour basis. For purposes
20    of this subsection (c), the total amount paid for electric
21    service includes without limitation amounts paid for
22    supply, transmission, distribution, surcharges, and add-on
23    taxes.
24        Notwithstanding the requirements of this subsection
25    (c), the total of renewable energy resources procured
26    pursuant to the procurement plan for any single year shall

 

 

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1    be reduced by an amount necessary to limit the annual
2    estimated average net increase due to the costs of these
3    resources included in the amounts paid by eligible retail
4    customers in connection with electric service to:
5            (A) in 2008, no more than 0.5% of the amount paid
6        per kilowatthour by those customers during the year
7        ending May 31, 2007;
8            (B) in 2009, the greater of an additional 0.5% of
9        the amount paid per kilowatthour by those customers
10        during the year ending May 31, 2008 or 1% of the amount
11        paid per kilowatthour by those customers during the
12        year ending May 31, 2007;
13            (C) in 2010, the greater of an additional 0.5% of
14        the amount paid per kilowatthour by those customers
15        during the year ending May 31, 2009 or 1.5% of the
16        amount paid per kilowatthour by those customers during
17        the year ending May 31, 2007;
18            (D) in 2011, the greater of an additional 0.5% of
19        the amount paid per kilowatthour by those customers
20        during the year ending May 31, 2010 or 2% of the amount
21        paid per kilowatthour by those customers during the
22        year ending May 31, 2007; and
23            (E) thereafter, the amount of renewable energy
24        resources procured pursuant to the procurement plan
25        for any single year shall be reduced by an amount
26        necessary to limit the estimated average net increase

 

 

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1        due to the cost of these resources included in the
2        amounts paid by eligible retail customers in
3        connection with electric service to no more than the
4        greater of 2.015% of the amount paid per kilowatthour
5        by those customers during the year ending May 31, 2007
6        or the incremental amount per kilowatthour paid for
7        these resources in 2011.
8            No later than June 30, 2011, the Commission shall
9        review the limitation on the amount of renewable energy
10        resources procured pursuant to this subsection (c) and
11        report to the General Assembly its findings as to
12        whether that limitation unduly constrains the
13        procurement of cost-effective renewable energy
14        resources.
15        (3) Through June 1, 2011, renewable energy resources
16    shall be counted for the purpose of meeting the renewable
17    energy standards set forth in paragraph (1) of this
18    subsection (c) only if they are generated from facilities
19    located in the State, provided that cost-effective
20    renewable energy resources are available from those
21    facilities. If those cost-effective resources are not
22    available in Illinois, they shall be procured in states
23    that adjoin Illinois and may be counted towards compliance.
24    If those cost-effective resources are not available in
25    Illinois or in states that adjoin Illinois, they shall be
26    purchased elsewhere and shall be counted towards

 

 

09900HB3328ham001- 44 -LRB099 10473 MLM 33016 a

1    compliance. After June 1, 2011, cost-effective renewable
2    energy resources located in Illinois and in states that
3    adjoin Illinois may be counted towards compliance with the
4    standards set forth in paragraph (1) of this subsection
5    (c). If those cost-effective resources are not available in
6    Illinois or in states that adjoin Illinois, they shall be
7    purchased elsewhere and shall be counted towards
8    compliance.
9        (4) The electric utility shall retire all renewable
10    energy credits used to comply with the standard.
11        (5) Beginning with the year commencing June 1, 2010, an
12    electric utility subject to this subsection (c) shall apply
13    the lesser of the maximum alternative compliance payment
14    rate or the most recent estimated alternative compliance
15    payment rate for its service territory for the
16    corresponding compliance period, established pursuant to
17    subsection (d) of Section 16-115D of the Public Utilities
18    Act to its retail customers that take service pursuant to
19    the electric utility's hourly pricing tariff or tariffs.
20    The electric utility shall retain all amounts collected as
21    a result of the application of the alternative compliance
22    payment rate or rates to such customers, and, beginning in
23    2011, the utility shall include in the information provided
24    under item (1) of subsection (d) of Section 16-111.5 of the
25    Public Utilities Act the amounts collected under the
26    alternative compliance payment rate or rates for the prior

 

 

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1    year ending May 31. Notwithstanding any limitation on the
2    procurement of renewable energy resources imposed by item
3    (2) of this subsection (c), the Agency shall increase its
4    spending on the purchase of renewable energy resources to
5    be procured by the electric utility for the next plan year
6    by an amount equal to the amounts collected by the utility
7    under the alternative compliance payment rate or rates in
8    the prior year ending May 31.
9        In the event of a curtailment as specified in
10    subsection (c) of Section 1-56, the Commission, pursuant to
11    an approved renewable energy resources plan, shall direct
12    the applicable utility to offer to purchase, using the
13    accumulated amounts collected pursuant to this paragraph
14    (5), renewable energy credits subject to curtailment in
15    accordance with the terms specified in subsection (c) of
16    Section 1-56; however, the offer to purchase the renewable
17    energy credits shall in no event include renewable energy
18    credits that have been purchased by any other means.
19        If, as a result of customer migration between
20    alternative retail electric suppliers and electric utility
21    electric supply service, the Agency has insufficient
22    moneys available in the Illinois Power Agency Renewable
23    Energy Resources Fund to cover the contract cost of
24    renewable energy credits procured pursuant to Section 1-56
25    of this Act, the Commission, pursuant to an approved
26    renewable energy resources plan, shall direct the

 

 

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1    applicable utility to offer to purchase, using the
2    accumulated amounts collected by the utility under the
3    alternative compliance payment required by this paragraph
4    (5), renewable energy credits that (i) are assigned to its
5    service territory pursuant to a Commission-approved
6    renewable energy resources plan; (ii) the Agency is unable
7    to purchase due to insufficient moneys available in the
8    Illinois Power Agency Renewable Energy Resources Fund as a
9    consequence of such customer migration; and (iii) are
10    subject to curtailment; however, such direction to offer to
11    purchase such renewable energy credits shall in no event
12    include renewable energy credits that have been purchased
13    by any other means. Nothing in this subsection (c) shall
14    require a supplier to sell its renewable energy credits in
15    this manner.
16        Purchases of curtailed renewable energy credits
17    originally contracted for by the Agency shall be made at
18    the contract price for each renewable energy credit. Except
19    as provided in this subsection (c), an electric utility's
20    purchase of curtailed renewable energy credits shall be
21    made in accordance with all other terms of the original
22    contract between the supplier and the Agency and shall not
23    include an obligation for physical deliveries of
24    electricity. An electric utility shall not purchase, nor
25    enter into contracts for, any other renewable energy
26    resources pursuant to this subsection (c), unless either

 

 

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1    (i) all of the renewable energy credits subject to
2    curtailment have been contracted for purchase or (ii) the
3    supplier has declined the applicable utility's offer to
4    purchase the renewable energy credits subject to
5    curtailment. Nothing in this paragraph alters the
6    limitations imposed by paragraph (2) of this subsection or
7    requires renewable energy credit purchases in excess of the
8    amount required to meet the renewable goals set forth in
9    this subsection (c).
10        Beginning April 1, 2012, and each year thereafter, the
11    Agency shall prepare a public report for the General
12    Assembly and Illinois Commerce Commission that shall
13    include, but not necessarily be limited to:
14            (A) a comparison of the costs associated with the
15        Agency's procurement of renewable energy resources to
16        (1) the Agency's costs associated with electricity
17        generated by other types of generation facilities and
18        (2) the benefits associated with the Agency's
19        procurement of renewable energy resources; and
20            (B) an analysis of the rate impacts associated with
21        the Illinois Power Agency's procurement of renewable
22        resources, including, but not limited to, any
23        long-term contracts, on the eligible retail customers
24        of electric utilities.
25        The analysis shall include the Agency's estimate of the
26    total dollar impact that the Agency's procurement of

 

 

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1    renewable resources has had on the annual electricity bills
2    of the customer classes that comprise each eligible retail
3    customer class taking service from an electric utility. The
4    Agency's report shall also analyze how the operation of the
5    alternative compliance payment mechanism, any long-term
6    contracts, or other aspects of the applicable renewable
7    portfolio standards impacts the rates of customers of
8    alternative retail electric suppliers.
9        (6) Beginning with the planning year commencing June 1,
10    2016, the procurement plan shall include a renewable energy
11    resources plan for the procurement of renewable energy
12    credits in accordance with the requirements of Section 1-56
13    of this Act and renewable energy resources in accordance
14    with the requirements of this Section. The renewable energy
15    resources plan shall ensure adequate, reliable,
16    affordable, efficient, and environmentally sustainable
17    renewable energy resources at the lowest total cost over
18    time, taking into account any benefits of price stability.
19    The renewable energy resources plan shall also include the
20    items set forth in subparagraphs (i) through (v) of
21    paragraph (5) of subsection (b) of Section 16-111.5 of the
22    Public Utilities Act.
23        Nothing in this paragraph (6) is intended to alter any
24    of the limitations or conditions otherwise imposed on the
25    purchase of renewable energy credits or renewable energy
26    resources by any other Section of this Act.

 

 

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1    (d) Clean coal portfolio standard.
2        (1) The procurement plans shall include electricity
3    generated using clean coal. Each utility shall enter into
4    one or more sourcing agreements with the initial clean coal
5    facility, as provided in paragraph (3) of this subsection
6    (d), covering electricity generated by the initial clean
7    coal facility representing at least 5% of each utility's
8    total supply to serve the load of eligible retail customers
9    in 2015 and each year thereafter, as described in paragraph
10    (3) of this subsection (d), subject to the limits specified
11    in paragraph (2) of this subsection (d). It is the goal of
12    the State that by January 1, 2025, 25% of the electricity
13    used in the State shall be generated by cost-effective
14    clean coal facilities. For purposes of this subsection (d),
15    "cost-effective" means that the expenditures pursuant to
16    such sourcing agreements do not cause the limit stated in
17    paragraph (2) of this subsection (d) to be exceeded and do
18    not exceed cost-based benchmarks, which shall be developed
19    to assess all expenditures pursuant to such sourcing
20    agreements covering electricity generated by clean coal
21    facilities, other than the initial clean coal facility, by
22    the procurement administrator, in consultation with the
23    Commission staff, Agency staff, and the procurement
24    monitor and shall be subject to Commission review and
25    approval.
26        A utility party to a sourcing agreement shall

 

 

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1    immediately retire any emission credits that it receives in
2    connection with the electricity covered by such agreement.
3        Utilities shall maintain adequate records documenting
4    the purchases under the sourcing agreement to comply with
5    this subsection (d) and shall file an accounting with the
6    load forecast that must be filed with the Agency by July 15
7    of each year, in accordance with subsection (d) of Section
8    16-111.5 of the Public Utilities Act.
9        A utility shall be deemed to have complied with the
10    clean coal portfolio standard specified in this subsection
11    (d) if the utility enters into a sourcing agreement as
12    required by this subsection (d).
13        (2) For purposes of this subsection (d), the required
14    execution of sourcing agreements with the initial clean
15    coal facility for a particular year shall be measured as a
16    percentage of the actual amount of electricity
17    (megawatt-hours) supplied by the electric utility to
18    eligible retail customers in the planning year ending
19    immediately prior to the agreement's execution. For
20    purposes of this subsection (d), the amount paid per
21    kilowatthour means the total amount paid for electric
22    service expressed on a per kilowatthour basis. For purposes
23    of this subsection (d), the total amount paid for electric
24    service includes without limitation amounts paid for
25    supply, transmission, distribution, surcharges and add-on
26    taxes.

 

 

09900HB3328ham001- 51 -LRB099 10473 MLM 33016 a

1        Notwithstanding the requirements of this subsection
2    (d), the total amount paid under sourcing agreements with
3    clean coal facilities pursuant to the procurement plan for
4    any given year shall be reduced by an amount necessary to
5    limit the annual estimated average net increase due to the
6    costs of these resources included in the amounts paid by
7    eligible retail customers in connection with electric
8    service to:
9            (A) in 2010, no more than 0.5% of the amount paid
10        per kilowatthour by those customers during the year
11        ending May 31, 2009;
12            (B) in 2011, the greater of an additional 0.5% of
13        the amount paid per kilowatthour by those customers
14        during the year ending May 31, 2010 or 1% of the amount
15        paid per kilowatthour by those customers during the
16        year ending May 31, 2009;
17            (C) in 2012, the greater of an additional 0.5% of
18        the amount paid per kilowatthour by those customers
19        during the year ending May 31, 2011 or 1.5% of the
20        amount paid per kilowatthour by those customers during
21        the year ending May 31, 2009;
22            (D) in 2013, the greater of an additional 0.5% of
23        the amount paid per kilowatthour by those customers
24        during the year ending May 31, 2012 or 2% of the amount
25        paid per kilowatthour by those customers during the
26        year ending May 31, 2009; and

 

 

09900HB3328ham001- 52 -LRB099 10473 MLM 33016 a

1            (E) thereafter, the total amount paid under
2        sourcing agreements with clean coal facilities
3        pursuant to the procurement plan for any single year
4        shall be reduced by an amount necessary to limit the
5        estimated average net increase due to the cost of these
6        resources included in the amounts paid by eligible
7        retail customers in connection with electric service
8        to no more than the greater of (i) 2.015% of the amount
9        paid per kilowatthour by those customers during the
10        year ending May 31, 2009 or (ii) the incremental amount
11        per kilowatthour paid for these resources in 2013.
12        These requirements may be altered only as provided by
13        statute.
14        No later than June 30, 2015, the Commission shall
15    review the limitation on the total amount paid under
16    sourcing agreements, if any, with clean coal facilities
17    pursuant to this subsection (d) and report to the General
18    Assembly its findings as to whether that limitation unduly
19    constrains the amount of electricity generated by
20    cost-effective clean coal facilities that is covered by
21    sourcing agreements.
22        (3) Initial clean coal facility. In order to promote
23    development of clean coal facilities in Illinois, each
24    electric utility subject to this Section shall execute a
25    sourcing agreement to source electricity from a proposed
26    clean coal facility in Illinois (the "initial clean coal

 

 

09900HB3328ham001- 53 -LRB099 10473 MLM 33016 a

1    facility") that will have a nameplate capacity of at least
2    500 MW when commercial operation commences, that has a
3    final Clean Air Act permit on the effective date of this
4    amendatory Act of the 95th General Assembly, and that will
5    meet the definition of clean coal facility in Section 1-10
6    of this Act when commercial operation commences. The
7    sourcing agreements with this initial clean coal facility
8    shall be subject to both approval of the initial clean coal
9    facility by the General Assembly and satisfaction of the
10    requirements of paragraph (4) of this subsection (d) and
11    shall be executed within 90 days after any such approval by
12    the General Assembly. The Agency and the Commission shall
13    have authority to inspect all books and records associated
14    with the initial clean coal facility during the term of
15    such a sourcing agreement. A utility's sourcing agreement
16    for electricity produced by the initial clean coal facility
17    shall include:
18            (A) a formula contractual price (the "contract
19        price") approved pursuant to paragraph (4) of this
20        subsection (d), which shall:
21                (i) be determined using a cost of service
22            methodology employing either a level or deferred
23            capital recovery component, based on a capital
24            structure consisting of 45% equity and 55% debt,
25            and a return on equity as may be approved by the
26            Federal Energy Regulatory Commission, which in any

 

 

09900HB3328ham001- 54 -LRB099 10473 MLM 33016 a

1            case may not exceed the lower of 11.5% or the rate
2            of return approved by the General Assembly
3            pursuant to paragraph (4) of this subsection (d);
4            and
5                (ii) provide that all miscellaneous net
6            revenue, including but not limited to net revenue
7            from the sale of emission allowances, if any,
8            substitute natural gas, if any, grants or other
9            support provided by the State of Illinois or the
10            United States Government, firm transmission
11            rights, if any, by-products produced by the
12            facility, energy or capacity derived from the
13            facility and not covered by a sourcing agreement
14            pursuant to paragraph (3) of this subsection (d) or
15            item (5) of subsection (d) of Section 16-115 of the
16            Public Utilities Act, whether generated from the
17            synthesis gas derived from coal, from SNG, or from
18            natural gas, shall be credited against the revenue
19            requirement for this initial clean coal facility;
20            (B) power purchase provisions, which shall:
21                (i) provide that the utility party to such
22            sourcing agreement shall pay the contract price
23            for electricity delivered under such sourcing
24            agreement;
25                (ii) require delivery of electricity to the
26            regional transmission organization market of the

 

 

09900HB3328ham001- 55 -LRB099 10473 MLM 33016 a

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

 

 

09900HB3328ham001- 56 -LRB099 10473 MLM 33016 a

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

 

 

09900HB3328ham001- 57 -LRB099 10473 MLM 33016 a

1            clause (i) shall be limited to an amount equal to
2            (1) the difference between the contract price
3            determined pursuant to subparagraph (A) of
4            paragraph (3) of this subsection (d) and the
5            day-ahead price for electricity delivered to the
6            regional transmission organization market of the
7            utility that is party to such sourcing agreement
8            (or any successor delivery point at which such
9            utility's supply obligations are financially
10            settled on an hourly basis) (the "reference
11            price") on the day preceding the day on which the
12            electricity is delivered to the initial clean coal
13            facility busbar, multiplied by (2) the quantity of
14            electricity determined pursuant to the preceding
15            clause (i); and
16                (iii) not require the utility to take physical
17            delivery of the electricity produced by the
18            facility;
19            (D) general provisions, which shall:
20                (i) specify a term of no more than 30 years,
21            commencing on the commercial operation date of the
22            facility;
23                (ii) provide that utilities shall maintain
24            adequate records documenting purchases under the
25            sourcing agreements entered into to comply with
26            this subsection (d) and shall file an accounting

 

 

09900HB3328ham001- 58 -LRB099 10473 MLM 33016 a

1            with the load forecast that must be filed with the
2            Agency by July 15 of each year, in accordance with
3            subsection (d) of Section 16-111.5 of the Public
4            Utilities Act;
5                (iii) provide that all costs associated with
6            the initial clean coal facility will be
7            periodically reported to the Federal Energy
8            Regulatory Commission and to purchasers in
9            accordance with applicable laws governing
10            cost-based wholesale power contracts;
11                (iv) permit the Illinois Power Agency to
12            assume ownership of the initial clean coal
13            facility, without monetary consideration and
14            otherwise on reasonable terms acceptable to the
15            Agency, if the Agency so requests no less than 3
16            years prior to the end of the stated contract term;
17                (v) require the owner of the initial clean coal
18            facility to provide documentation to the
19            Commission each year, starting in the facility's
20            first year of commercial operation, accurately
21            reporting the quantity of carbon emissions from
22            the facility that have been captured and
23            sequestered and report any quantities of carbon
24            released from the site or sites at which carbon
25            emissions were sequestered in prior years, based
26            on continuous monitoring of such sites. If, in any

 

 

09900HB3328ham001- 59 -LRB099 10473 MLM 33016 a

1            year after the first year of commercial operation,
2            the owner of the facility fails to demonstrate that
3            the initial clean coal facility captured and
4            sequestered at least 50% of the total carbon
5            emissions that the facility would otherwise emit
6            or that sequestration of emissions from prior
7            years has failed, resulting in the release of
8            carbon dioxide into the atmosphere, the owner of
9            the facility must offset excess emissions. Any
10            such carbon offsets must be permanent, additional,
11            verifiable, real, located within the State of
12            Illinois, and legally and practicably enforceable.
13            The cost of such offsets for the facility that are
14            not recoverable shall not exceed $15 million in any
15            given year. No costs of any such purchases of
16            carbon offsets may be recovered from a utility or
17            its customers. All carbon offsets purchased for
18            this purpose and any carbon emission credits
19            associated with sequestration of carbon from the
20            facility must be permanently retired. The initial
21            clean coal facility shall not forfeit its
22            designation as a clean coal facility if the
23            facility fails to fully comply with the applicable
24            carbon sequestration requirements in any given
25            year, provided the requisite offsets are
26            purchased. However, the Attorney General, on

 

 

09900HB3328ham001- 60 -LRB099 10473 MLM 33016 a

1            behalf of the People of the State of Illinois, may
2            specifically enforce the facility's sequestration
3            requirement and the other terms of this contract
4            provision. Compliance with the sequestration
5            requirements and offset purchase requirements
6            specified in paragraph (3) of this subsection (d)
7            shall be reviewed annually by an independent
8            expert retained by the owner of the initial clean
9            coal facility, with the advance written approval
10            of the Attorney General. The Commission may, in the
11            course of the review specified in item (vii),
12            reduce the allowable return on equity for the
13            facility if the facility wilfully fails to comply
14            with the carbon capture and sequestration
15            requirements set forth in this item (v);
16                (vi) include limits on, and accordingly
17            provide for modification of, the amount the
18            utility is required to source under the sourcing
19            agreement consistent with paragraph (2) of this
20            subsection (d);
21                (vii) require Commission review: (1) to
22            determine the justness, reasonableness, and
23            prudence of the inputs to the formula referenced in
24            subparagraphs (A)(i) through (A)(iii) of paragraph
25            (3) of this subsection (d), prior to an adjustment
26            in those inputs including, without limitation, the

 

 

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1            capital structure and return on equity, fuel
2            costs, and other operations and maintenance costs
3            and (2) to approve the costs to be passed through
4            to customers under the sourcing agreement by which
5            the utility satisfies its statutory obligations.
6            Commission review shall occur no less than every 3
7            years, regardless of whether any adjustments have
8            been proposed, and shall be completed within 9
9            months;
10                (viii) limit the utility's obligation to such
11            amount as the utility is allowed to recover through
12            tariffs filed with the Commission, provided that
13            neither the clean coal facility nor the utility
14            waives any right to assert federal pre-emption or
15            any other argument in response to a purported
16            disallowance of recovery costs;
17                (ix) limit the utility's or alternative retail
18            electric supplier's obligation to incur any
19            liability until such time as the facility is in
20            commercial operation and generating power and
21            energy and such power and energy is being delivered
22            to the facility busbar;
23                (x) provide that the owner or owners of the
24            initial clean coal facility, which is the
25            counterparty to such sourcing agreement, shall
26            have the right from time to time to elect whether

 

 

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1            the obligations of the utility party thereto shall
2            be governed by the power purchase provisions or the
3            contract for differences provisions;
4                (xi) append documentation showing that the
5            formula rate and contract, insofar as they relate
6            to the power purchase provisions, have been
7            approved by the Federal Energy Regulatory
8            Commission pursuant to Section 205 of the Federal
9            Power Act;
10                (xii) provide that any changes to the terms of
11            the contract, insofar as such changes relate to the
12            power purchase provisions, are subject to review
13            under the public interest standard applied by the
14            Federal Energy Regulatory Commission pursuant to
15            Sections 205 and 206 of the Federal Power Act; and
16                (xiii) conform with customary lender
17            requirements in power purchase agreements used as
18            the basis for financing non-utility generators.
19        (4) Effective date of sourcing agreements with the
20    initial clean coal facility.
21        Any proposed sourcing agreement with the initial clean
22    coal facility shall not become effective unless the
23    following reports are prepared and submitted and
24    authorizations and approvals obtained:
25            (i) Facility cost report. The owner of the initial
26        clean coal facility shall submit to the Commission, the

 

 

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1        Agency, and the General Assembly a front-end
2        engineering and design study, a facility cost report,
3        method of financing (including but not limited to
4        structure and associated costs), and an operating and
5        maintenance cost quote for the facility (collectively
6        "facility cost report"), which shall be prepared in
7        accordance with the requirements of this paragraph (4)
8        of subsection (d) of this Section, and shall provide
9        the Commission and the Agency access to the work
10        papers, relied upon documents, and any other backup
11        documentation related to the facility cost report.
12            (ii) Commission report. Within 6 months following
13        receipt of the facility cost report, the Commission, in
14        consultation with the Agency, shall submit a report to
15        the General Assembly setting forth its analysis of the
16        facility cost report. Such report shall include, but
17        not be limited to, a comparison of the costs associated
18        with electricity generated by the initial clean coal
19        facility to the costs associated with electricity
20        generated by other types of generation facilities, an
21        analysis of the rate impacts on residential and small
22        business customers over the life of the sourcing
23        agreements, and an analysis of the likelihood that the
24        initial clean coal facility will commence commercial
25        operation by and be delivering power to the facility's
26        busbar by 2016. To assist in the preparation of its

 

 

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1        report, the Commission, in consultation with the
2        Agency, may hire one or more experts or consultants,
3        the costs of which shall be paid for by the owner of
4        the initial clean coal facility. The Commission and
5        Agency may begin the process of selecting such experts
6        or consultants prior to receipt of the facility cost
7        report.
8            (iii) General Assembly approval. The proposed
9        sourcing agreements shall not take effect unless,
10        based on the facility cost report and the Commission's
11        report, the General Assembly enacts authorizing
12        legislation approving (A) the projected price, stated
13        in cents per kilowatthour, to be charged for
14        electricity generated by the initial clean coal
15        facility, (B) the projected impact on residential and
16        small business customers' bills over the life of the
17        sourcing agreements, and (C) the maximum allowable
18        return on equity for the project; and
19            (iv) Commission review. If the General Assembly
20        enacts authorizing legislation pursuant to
21        subparagraph (iii) approving a sourcing agreement, the
22        Commission shall, within 90 days of such enactment,
23        complete a review of such sourcing agreement. During
24        such time period, the Commission shall implement any
25        directive of the General Assembly, resolve any
26        disputes between the parties to the sourcing agreement

 

 

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1        concerning the terms of such agreement, approve the
2        form of such agreement, and issue an order finding that
3        the sourcing agreement is prudent and reasonable.
4        The facility cost report shall be prepared as follows:
5            (A) The facility cost report shall be prepared by
6        duly licensed engineering and construction firms
7        detailing the estimated capital costs payable to one or
8        more contractors or suppliers for the engineering,
9        procurement and construction of the components
10        comprising the initial clean coal facility and the
11        estimated costs of operation and maintenance of the
12        facility. The facility cost report shall include:
13                (i) an estimate of the capital cost of the core
14            plant based on one or more front end engineering
15            and design studies for the gasification island and
16            related facilities. The core plant shall include
17            all civil, structural, mechanical, electrical,
18            control, and safety systems.
19                (ii) an estimate of the capital cost of the
20            balance of the plant, including any capital costs
21            associated with sequestration of carbon dioxide
22            emissions and all interconnects and interfaces
23            required to operate the facility, such as
24            transmission of electricity, construction or
25            backfeed power supply, pipelines to transport
26            substitute natural gas or carbon dioxide, potable

 

 

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1            water supply, natural gas supply, water supply,
2            water discharge, landfill, access roads, and coal
3            delivery.
4            The quoted construction costs shall be expressed
5        in nominal dollars as of the date that the quote is
6        prepared and shall include capitalized financing costs
7        during construction, taxes, insurance, and other
8        owner's costs, and an assumed escalation in materials
9        and labor beyond the date as of which the construction
10        cost quote is expressed.
11            (B) The front end engineering and design study for
12        the gasification island and the cost study for the
13        balance of plant shall include sufficient design work
14        to permit quantification of major categories of
15        materials, commodities and labor hours, and receipt of
16        quotes from vendors of major equipment required to
17        construct and operate the clean coal facility.
18            (C) The facility cost report shall also include an
19        operating and maintenance cost quote that will provide
20        the estimated cost of delivered fuel, personnel,
21        maintenance contracts, chemicals, catalysts,
22        consumables, spares, and other fixed and variable
23        operations and maintenance costs. The delivered fuel
24        cost estimate will be provided by a recognized third
25        party expert or experts in the fuel and transportation
26        industries. The balance of the operating and

 

 

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

 

 

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1        reimbursed through Coal Development Bonds.
2        (5) Re-powering and retrofitting coal-fired power
3    plants previously owned by Illinois utilities to qualify as
4    clean coal facilities. During the 2009 procurement
5    planning process and thereafter, the Agency and the
6    Commission shall consider sourcing agreements covering
7    electricity generated by power plants that were previously
8    owned by Illinois utilities and that have been or will be
9    converted into clean coal facilities, as defined by Section
10    1-10 of this Act. Pursuant to such procurement planning
11    process, the owners of such facilities may propose to the
12    Agency sourcing agreements with utilities and alternative
13    retail electric suppliers required to comply with
14    subsection (d) of this Section and item (5) of subsection
15    (d) of Section 16-115 of the Public Utilities Act, covering
16    electricity generated by such facilities. In the case of
17    sourcing agreements that are power purchase agreements,
18    the contract price for electricity sales shall be
19    established on a cost of service basis. In the case of
20    sourcing agreements that are contracts for differences,
21    the contract price from which the reference price is
22    subtracted shall be established on a cost of service basis.
23    The Agency and the Commission may approve any such utility
24    sourcing agreements that do not exceed cost-based
25    benchmarks developed by the procurement administrator, in
26    consultation with the Commission staff, Agency staff and

 

 

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1    the procurement monitor, subject to Commission review and
2    approval. The Commission shall have authority to inspect
3    all books and records associated with these clean coal
4    facilities during the term of any such contract.
5        (6) Costs incurred under this subsection (d) or
6    pursuant to a contract entered into under this subsection
7    (d) shall be deemed prudently incurred and reasonable in
8    amount and the electric utility shall be entitled to full
9    cost recovery pursuant to the tariffs filed with the
10    Commission.
11    (e) The draft procurement plans are subject to public
12comment, as required by Section 16-111.5 of the Public
13Utilities Act.
14    (f) The Agency shall submit the final procurement plan to
15the Commission. The Agency shall revise a procurement plan if
16the Commission determines that it does not meet the standards
17set forth in Section 16-111.5 of the Public Utilities Act.
18    (g) The Agency shall assess fees to each affected utility
19to recover the costs incurred in preparation of the annual
20procurement plan for the utility.
21    (h) The Agency shall assess fees to each bidder to recover
22the costs incurred in connection with a competitive procurement
23process.
24(Source: P.A. 97-325, eff. 8-12-11; 97-616, eff. 10-26-11;
2597-618, eff. 10-26-11; 97-658, eff. 1-13-12; 97-813, eff.
267-13-12; 98-463, eff. 8-16-13.)
 

 

 

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1    Section 10. The Public Utilities Act is amended by changing
2Sections 8-103, 8-103A, 8-104, 16-107, 16-107.5, 16-111.5,
316-111.5B, and 16-115D and by adding Sections 9-105, 9-106,
416-103.3, 16-103.4, 16-107.6, 16-108.9, 16-108.10, 16-108.11,
5and 16-108.12 as follows:
 
6    (220 ILCS 5/8-103)
7    Sec. 8-103. Energy efficiency and demand-response
8measures.
9    (a) It is the policy of the State that electric utilities
10are required to use cost-effective energy efficiency and
11demand-response measures to reduce delivery load. Requiring
12investment in cost-effective energy efficiency and
13demand-response measures will reduce direct and indirect costs
14to consumers by decreasing environmental impacts and by
15avoiding or delaying the need for new generation, transmission,
16and distribution infrastructure. It serves the public interest
17to allow electric utilities to recover costs for reasonably and
18prudently incurred expenses for energy efficiency and
19demand-response measures. As used in this Section,
20"cost-effective" means that the measures satisfy the total
21resource cost test. The low-income measures described in
22subsection (e-5) and paragraph (4) of subsection (g) subsection
23(f)(4) of this Section shall not be required to meet the total
24resource cost test. For purposes of this Section, the terms

 

 

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1"energy-efficiency", "demand-response", "electric utility",
2and "total resource cost test" shall have the meanings set
3forth in the Illinois Power Agency Act. For purposes of this
4Section, the amount per kilowatthour means the total amount
5paid for electric service expressed on a per kilowatthour
6basis. For purposes of this Section, the total amount paid for
7electric service includes without limitation estimated amounts
8paid for supply, transmission, distribution, surcharges, and
9add-on-taxes.
10    (b) Electric utilities shall implement cost-effective
11energy efficiency measures to meet the following incremental
12annual energy savings goals:
13        (1) 0.2% of energy delivered in the year commencing
14    June 1, 2008;
15        (2) 0.4% of energy delivered in the year commencing
16    June 1, 2009;
17        (3) 0.6% of energy delivered in the year commencing
18    June 1, 2010;
19        (4) 0.8% of energy delivered in the year commencing
20    June 1, 2011;
21        (5) 1% of energy delivered in the year commencing June
22    1, 2012;
23        (6) 1.4% of energy delivered in the year commencing
24    June 1, 2013;
25        (7) 1.8% of energy delivered in the year commencing
26    June 1, 2014; and

 

 

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1        (8) 2% of energy delivered in the year commencing June
2    1, 2015 and June 1, 2016; and each year thereafter.
3        (9) 2% of energy delivered in the year commencing
4    January 1, 2018 and in each year thereafter.
5    Electric utilities may comply with this subsection (b) by
6meeting the annual incremental savings goal in the applicable
7year or by showing that the total cumulative annual savings
8within a multi-year 3-year planning period associated with
9measures implemented after May 31, 2014 was equal to the sum of
10each annual incremental savings requirement from the first day
11of the multi-year planning period May 31, 2014 through the last
12day of the multi-year planning period end of the applicable
13year.
14    (b-5) Energy efficiency measures shall include
15cost-effective voltage optimization measures. Notwithstanding
16the limitations set forth in subsection (d) of this Section,
17costs incurred by an electric utility to implement
18cost-effective voltage optimization measures pursuant to
19Section 16-108.11 of this Act shall be recoverable pursuant to
20the provisions of Article IX or Section 16-108.5 of this Act,
21and the associated energy savings shall be included under and
22applied to achievement of the energy savings goals set forth in
23subsection (b) of this Section. Beginning with those multi-year
24plans commencing after December 31, 2017, each electric utility
25shall address cost-effective voltage optimization measures in
26its assessments submitted pursuant to paragraph (8) of

 

 

09900HB3328ham001- 73 -LRB099 10473 MLM 33016 a

1subsection (g) of this Section, and the costs incurred by a
2utility to implement such measures pursuant to a
3Commission-approved plan shall be recovered pursuant to the
4provisions of Article IX or Section 16-108.5 of this Act.
5    In the event an electric utility jointly offers an energy
6efficiency measure or program with a gas utility pursuant to
7plans approved under this Section and Section 8-104 of this
8Act, the electric utility may continue offering the program,
9including the gas energy efficiency measures, in the event the
10gas utility is unable to continue funding the program. In that
11event, up to 30% of the annual savings goal calculated pursuant
12to subsection (b) of this Section, as modified pursuant to
13subsection (d) of this Section, if applicable, may be met
14through savings of fuels other than electricity, and the
15savings value associated with such other fuels shall be
16converted to electric energy savings on an equivalent site Btu
17basis. An electric utility may recover the costs of offering
18the gas energy efficiency measures pursuant to this subsection.
19    (c) Electric utilities shall implement cost-effective
20demand-response measures to reduce peak demand by 0.1% over the
21prior year for eligible retail customers, as defined in Section
2216-111.5 of this Act, and for customers that elect hourly
23service from the utility pursuant to Section 16-107 of this
24Act, provided those customers have not been declared
25competitive. Notwithstanding any law, rule, regulation, or
26order to the contrary, this This requirement commences June 1,

 

 

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12008 and continues until December 31, 2017 for 10 years.
2    (d) Notwithstanding the requirements of subsections (b)
3and (c) of this Section, an electric utility shall reduce the
4amount of energy efficiency and demand-response measures
5implemented for any single 12-month plan year by an amount
6necessary to limit the estimated average net increase due to
7the cost of these measures included in the amounts paid by
8retail customers in connection with electric service to no more
9than the incremental amount per kilowatthour paid for these
10measures in 2011. The changes made in this subsection (d) by
11this amendatory Act of the 99th General Assembly are intended
12to be a restatement and clarification of existing law. over a
133-year planning period by an amount necessary to limit the
14estimated average annual increase in the amounts paid by retail
15customers in connection with electric service due to the cost
16of those measures to:
17        (1) in 2008, no more than 0.5% of the amount paid per
18    kilowatthour by those customers during the year ending May
19    31, 2007;
20        (2) in 2009, the greater of an additional 0.5% of the
21    amount paid per kilowatthour by those customers during the
22    year ending May 31, 2008 or 1% of the amount paid per
23    kilowatthour by those customers during the year ending May
24    31, 2007;
25        (3) in 2010, the greater of an additional 0.5% of the
26    amount paid per kilowatthour by those customers during the

 

 

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1    year ending May 31, 2009 or 1.5% of the amount paid per
2    kilowatthour by those customers during the year ending May
3    31, 2007;
4        (4) in 2011, the greater of an additional 0.5% of the
5    amount paid per kilowatthour by those customers during the
6    year ending May 31, 2010 or 2% of the amount paid per
7    kilowatthour by those customers during the year ending May
8    31, 2007; and
9        (5) thereafter, the amount of energy efficiency and
10    demand-response measures implemented for any single year
11    shall be reduced by an amount necessary to limit the
12    estimated average net increase due to the cost of these
13    measures included in the amounts paid by eligible retail
14    customers in connection with electric service to no more
15    than the greater of 2.015% of the amount paid per
16    kilowatthour by those customers during the year ending May
17    31, 2007 or the incremental amount per kilowatthour paid
18    for these measures in 2011.
19    No later than June 30, 2011, the Commission shall review
20the limitation on the amount of energy efficiency and
21demand-response measures implemented pursuant to this Section
22and report to the General Assembly its findings as to whether
23that limitation unduly constrains the procurement of energy
24efficiency and demand-response measures.
25    (e) The following provisions apply to those multi-year
26plans that commence prior to January 1, 2018: Electric

 

 

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1utilities shall be responsible for overseeing the design,
2development, and filing of energy efficiency and
3demand-response plans with the Commission. (i) electric
4Electric utilities shall implement 100% of the demand-response
5measures in the plans; . (ii) electric Electric utilities shall
6implement 75% of the energy efficiency measures approved by the
7Commission, and may, as part of that implementation, outsource
8various aspects of program development and implementation; and
9(iii) the . The remaining 25% of those energy efficiency
10measures approved by the Commission shall be implemented by the
11Department of Commerce and Economic Opportunity, and must be
12designed in conjunction with the utility and the filing
13process. The Department may outsource development and
14implementation of energy efficiency measures. A minimum of 10%
15of the entire portfolio of cost-effective energy efficiency
16measures shall be procured from units of local government,
17municipal corporations, school districts, and community
18college districts. The Department shall coordinate the
19implementation of these measures.
20    The apportionment of the dollars to cover the costs to
21implement the Department's share of the portfolio of energy
22efficiency measures shall be made to the Department once the
23Department has executed rebate agreements, grants, or
24contracts for energy efficiency measures and provided
25supporting documentation for those rebate agreements, grants,
26and contracts to the utility. The Department is authorized to

 

 

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1adopt any rules necessary and prescribe procedures in order to
2ensure compliance by applicants in carrying out the purposes of
3rebate agreements for energy efficiency measures implemented
4by the Department made under this Section.
5    The details of the measures implemented by the Department
6shall be submitted by the Department to the Commission in
7connection with the utility's filing regarding the energy
8efficiency and demand-response measures that the utility
9implements.
10    The portfolio of measures administered by both the
11utilities and the Department shall, in combination, be designed
12to achieve the annual savings targets described in subsections
13(b) and (c) of this Section, as modified by subsection (d) of
14this Section.
15    The utility and the Department shall agree upon a
16reasonable portfolio of measures and determine the measurable
17corresponding percentage of the savings goals associated with
18measures implemented by the utility or Department.
19    No utility shall be assessed a penalty under subsection (g)
20of this Section for failure to make a timely filing if that
21failure is the result of a lack of agreement with the
22Department with respect to the allocation of responsibilities
23or related costs or target assignments. In that case, the
24Department and the utility shall file their respective plans
25with the Commission and the Commission shall determine an
26appropriate division of measures and programs that meets the

 

 

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1requirements of this Section.
2    (e-5) For those multi-year plans that commence after
3December 31, 2017, electric utilities shall be responsible for
4overseeing the design, development, and filing of energy
5efficiency plans with the Commission, and may, as part of that
6implementation, outsource various aspects of program
7development and implementation. A minimum of 10% of the entire
8portfolio of cost-effective energy efficiency measures shall
9be procured from units of local government, municipal
10corporations, school districts, and community college
11districts. The utilities shall also implement energy
12efficiency measures targeted at households at or below 80% of
13area median income. The funding for these measures shall be
14proportionate to the total annual utility revenues in Illinois
15from households at or below 80% of area median income.
16    (f) A utility providing approved energy efficiency and
17demand-response measures in the State shall be permitted to
18recover costs of those measures through an automatic adjustment
19clause tariff filed with and approved by the Commission. The
20tariff shall be established outside the context of a general
21rate case. Each year the Commission shall initiate a review to
22reconcile any amounts collected with the actual costs and to
23determine the required adjustment to the annual tariff factor
24to match annual expenditures. Beginning January 1, 2016, the
25utility may amortize over a 5-year period the full amount of
26its operating expenses incurred pursuant to this Section for

 

 

09900HB3328ham001- 79 -LRB099 10473 MLM 33016 a

1each annual period, provided that such expenses do not include
2those costs associated with voltage optimization measures that
3are described in subsection (b-5) of this Section and Section
416-108.11 of this Act that are being recovered pursuant to
5Article IX or Section 16-108.5 of this Act. A utility that
6recovers operating expenses through an automatic adjustment
7clause tariff shall reflect any unamortized balance as of
8December 31 for a given year in a regulatory asset. The utility
9shall also earn a return on that balance, less any related
10deferred taxes, at an annual rate equal to the utility's
11weighted average cost of capital as approved by the Commission
12in its most recent order applicable to that utility under
13Article IX or Section 16-108.5 of this Act, including a revenue
14conversion factor calculated to recover or refund all
15additional income taxes that may be payable or receivable as a
16result of that return. An electric utility's election to
17amortize its operating expenses pursuant to this subsection (f)
18shall have no effect on the calculations performed under
19subsection (d) of this Section, and such calculations shall not
20limit the utility's ability to recover all of its amortized
21costs.
22    Prior to January 1, 2018, each Each utility shall include,
23in its recovery of costs, the costs estimated for both the
24utility's and the Department's implementation of energy
25efficiency and demand-response measures. Costs collected by
26the utility for measures implemented by the Department shall be

 

 

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1submitted to the Department pursuant to Section 605-323 of the
2Civil Administrative Code of Illinois, shall be deposited into
3the Energy Efficiency Portfolio Standards Fund, and shall be
4used by the Department solely for the purpose of implementing
5these measures. A utility shall not be required to advance any
6moneys to the Department but only to forward such funds as it
7has collected. The Department shall report to the Commission on
8an annual basis regarding the costs actually incurred by the
9Department in the implementation of the measures. Any changes
10to the costs of energy efficiency measures as a result of plan
11modifications shall be appropriately reflected in amounts
12recovered by the utility and turned over to the Department.
13    The portfolio of measures, administered by both the
14utilities and the Department, shall, in combination, be
15designed to achieve the annual savings targets described in
16subsections (b) and (c) of this Section, as modified by
17subsection (d) of this Section.
18    The utility and the Department shall agree upon a
19reasonable portfolio of measures and determine the measurable
20corresponding percentage of the savings goals associated with
21measures implemented by the utility or Department.
22    No utility shall be assessed a penalty under subsection (f)
23of this Section for failure to make a timely filing if that
24failure is the result of a lack of agreement with the
25Department with respect to the allocation of responsibilities
26or related costs or target assignments. In that case, the

 

 

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1Department and the utility shall file their respective plans
2with the Commission and the Commission shall determine an
3appropriate division of measures and programs that meets the
4requirements of this Section.
5    If the Department is unable to meet incremental annual
6performance goals for the portion of the portfolio implemented
7by the Department, then the utility and the Department shall
8jointly submit a modified filing to the Commission explaining
9the performance shortfall and recommending an appropriate
10course going forward, including any program modifications that
11may be appropriate in light of the evaluations conducted under
12item (7) of subsection (f) of this Section. In this case, the
13utility obligation to collect the Department's costs and turn
14over those funds to the Department under this subsection (e)
15shall continue only if the Commission approves the
16modifications to the plan proposed by the Department.
17    (g) (f) No later than November 15, 2007, each electric
18utility shall file an energy efficiency and demand-response
19plan with the Commission to meet the energy efficiency and
20demand-response standards for 2008 through 2010. No later than
21October 1, 2010, each electric utility shall file an energy
22efficiency and demand-response plan with the Commission to meet
23the energy efficiency and demand-response standards for 2011
24through 2013. No later Every 3 years thereafter, each electric
25utility shall file, no later than September 1, 2013, each
26electric utility shall file an energy efficiency and

 

 

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1demand-response plan with the Commission to meet the energy
2efficiency and demand-response standards for 2014 through
32017. Beginning March 1, 2017 and every 4 years thereafter,
4each electric utility shall file an energy efficiency plan with
5the Commission to meet the energy efficiency standards for the
6applicable 4-year period. If a utility does not file such a
7plan by March September 1 of an applicable year, it shall face
8a penalty of $100,000 per day until the plan is filed. Each
9utility's plan shall set forth the utility's proposals to meet
10the utility's portion of the energy efficiency standards
11identified in subsection (b), as modified by subsections (d)
12and (e) of this Section, and, for multi-year plans that
13commence prior to January 1, 2018, the demand-response
14standards identified in subsection (c) of this Section as
15modified by subsections (d) and (e), taking into account the
16unique circumstances of the utility's service territory. The
17Commission shall seek public comment on the utility's plan and
18shall issue an order approving or disapproving each plan within
196 5 months after its submission. If the Commission disapproves
20a plan, the Commission shall, within 30 days, describe in
21detail the reasons for the disapproval and describe a path by
22which the utility may file a revised draft of the plan to
23address the Commission's concerns satisfactorily. If the
24utility does not refile with the Commission within 60 days, the
25utility shall be subject to penalties at a rate of $100,000 per
26day until the plan is filed. This process shall continue, and

 

 

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1penalties shall accrue, until the utility has successfully
2filed a portfolio of energy efficiency and demand-response
3measures. Penalties shall be deposited into the Energy
4Efficiency Trust Fund. In submitting proposed energy
5efficiency and demand-response plans and funding levels to meet
6the savings goals adopted by this Act the utility shall:
7        (1) Demonstrate that its proposed energy efficiency
8    measures and, if applicable, demand-response measures will
9    achieve the requirements that are identified in
10    subsections (b) and (c) of this Section, as modified by
11    subsections (d) and (e).
12        (2) Present specific proposals to implement new
13    building and appliance standards that have been placed into
14    effect.
15        (3) Present estimates of the total amount paid for
16    electric service expressed on a per kilowatthour basis
17    associated with the proposed portfolio of measures
18    designed to meet the requirements that are identified in
19    subsections (b) and (c) of this Section, as modified by
20    subsections (d) and (e).
21        (4) For those multi-year plans that commence prior to
22    January 1, 2018, coordinate Coordinate with the Department
23    to present a portfolio of energy efficiency measures
24    proportionate to the share of total annual utility revenues
25    in Illinois from households at or below 150% of the poverty
26    level. The energy efficiency programs shall be targeted to

 

 

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1    households with incomes at or below 80% of area median
2    income.
3        (5) Demonstrate that its overall portfolio of energy
4    efficiency and demand-response measures, not including
5    low-income programs described in covered by item (4) of
6    this subsection (g) and subsection (e-5) of this Section
7    (f), are cost-effective using the total resource cost test
8    and represent a diverse cross-section of opportunities for
9    customers of all rate classes to participate in the
10    programs.
11        (6) Include a proposed cost-recovery tariff mechanism
12    to fund the proposed energy efficiency and demand-response
13    measures and to ensure the recovery of the prudently and
14    reasonably incurred costs of Commission-approved programs.
15        (7) Provide for an annual independent evaluation of the
16    performance of the cost-effectiveness of the utility's
17    portfolio of measures and, prior to January 1, 2018, the
18    Department's portfolio of measures, as well as a full
19    review of the multi-year plan 3-year results of the broader
20    net program impacts and, to the extent practical, for
21    adjustment of the measures on a going-forward basis as a
22    result of the evaluations. The resources dedicated to
23    evaluation shall not exceed 3% of portfolio resources in
24    any given year.
25        (8) For those multi-year plans commencing after
26    December 31, 2017 where the requirements of subsection (b)

 

 

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1    of this Section will require modification by subsection (d)
2    of this Section, present an assessment of additional
3    cost-effective energy efficiency programs or measures that
4    could be included in the multi-year plan. The assessment
5    shall include:
6            (A) the most recent analysis submitted pursuant to
7        Section 8-103A of this Act; and
8            (B) an analysis showing that the new or expanded
9        cost-effective energy efficiency programs or measures
10        would lead to a reduction in the overall cost of
11        electric service.
12        Notwithstanding the limitations imposed by subsection
13    (d) of this Section, the Commission may approve
14    cost-effective energy efficiency programs or measures
15    identified in the assessment that are designed to achieve
16    no more than the unmet portion of the utility's energy
17    savings goals calculated pursuant to subsection (b) of this
18    Section for the applicable multi-year planning period. For
19    purposes of this Section, the "unmet portion" shall be
20    calculated as the difference between the utility's energy
21    savings goals calculated pursuant to subsection (b) of this
22    Act for the applicable multi-year planning period and the
23    utility's energy savings goals as modified by subsection
24    (d) of this Section for the same planning period.
25    Notwithstanding the limitations set forth in subsection
26    (d) of this Section, the utility shall recover all of its

 

 

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1    costs incurred to implement any energy efficiency programs
2    or measures approved by the Commission pursuant to this
3    paragraph (8) through the cost recovery mechanism
4    specified in subsection (f) of this Section.
5    (h) (g) No more than 3% of energy efficiency and
6demand-response program revenue may be allocated for
7demonstration of breakthrough equipment and devices.
8    (i) Electric utilities' 3-year energy efficiency and
9demand-response plans approved by the Commission on or before
10the effective date of this amendatory Act of the 99th General
11Assembly for the period June 1, 2014 through May 31, 2017 shall
12continue to be in force and effect through December 31, 2017 so
13that the energy efficiency programs set forth in those plans
14continue to be offered during the period June 1, 2017 through
15December 31, 2017. Each utility is authorized to increase, on a
16pro-rata basis, the energy savings goals and budgets approved
17in its plan to reflect the additional 7 months of the plan's
18operation.
19    (j) (h) This Section does not apply to an electric utility
20that on December 31, 2005 provided electric service to fewer
21than 100,000 customers in Illinois.
22    (i) If, after 2 years, an electric utility fails to meet
23the efficiency standard specified in subsection (b) of this
24Section, as modified by subsections (d) and (e), it shall make
25a contribution to the Low-Income Home Energy Assistance
26Program. The combined total liability for failure to meet the

 

 

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1goal shall be $1,000,000, which shall be assessed as follows: a
2large electric utility shall pay $665,000, and a medium
3electric utility shall pay $335,000. If, after 3 years, an
4electric utility fails to meet the efficiency standard
5specified in subsection (b) of this Section, as modified by
6subsections (d) and (e), it shall make a contribution to the
7Low-Income Home Energy Assistance Program. The combined total
8liability for failure to meet the goal shall be $1,000,000,
9which shall be assessed as follows: a large electric utility
10shall pay $665,000, and a medium electric utility shall pay
11$335,000. In addition, the responsibility for implementing the
12energy efficiency measures of the utility making the payment
13shall be transferred to the Illinois Power Agency if, after 3
14years, or in any subsequent 3-year period, the utility fails to
15meet the efficiency standard specified in subsection (b) of
16this Section, as modified by subsections (d) and (e). The
17Agency shall implement a competitive procurement program to
18procure resources necessary to meet the standards specified in
19this Section as modified by subsections (d) and (e), with costs
20for those resources to be recovered in the same manner as
21products purchased through the procurement plan as provided in
22Section 16-111.5. The Director shall implement this
23requirement in connection with the procurement plan as provided
24in Section 16-111.5.
25    For purposes of this Section, (i) a "large electric
26utility" is an electric utility that, on December 31, 2005,

 

 

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1served more than 2,000,000 electric customers in Illinois; (ii)
2a "medium electric utility" is an electric utility that, on
3December 31, 2005, served 2,000,000 or fewer but more than
4100,000 electric customers in Illinois; and (iii) Illinois
5electric utilities that are affiliated by virtue of a common
6parent company are considered a single electric utility.
7    (k) (j) If, after 3 years, or any subsequent 3-year period
8through December 31, 2017, the Department fails to implement
9the Department's share of energy efficiency measures required
10by the standards in subsection (b), then the Illinois Power
11Agency may assume responsibility for and control of the
12Department's share of the required energy efficiency measures.
13The Agency shall implement a competitive procurement program to
14procure resources necessary to meet the standards specified in
15this Section, with the costs of these resources to be recovered
16in the same manner as provided for the Department in this
17Section.
18    (l) (k) No electric utility shall be deemed to have failed
19to meet the energy efficiency standards to the extent any such
20failure is due to a failure of the Department or the Agency.
21(Source: P.A. 97-616, eff. 10-26-11; 97-841, eff. 7-20-12;
2298-90, eff. 7-15-13.)
 
23    (220 ILCS 5/8-103A)
24    Sec. 8-103A. Energy efficiency analysis. An Beginning in
252013, an electric utility subject to the requirements of

 

 

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1Section 8-103 of this Act shall include in its energy
2efficiency and demand-response plan submitted pursuant to
3subsection (g) (f) of Section 8-103 an analysis of additional
4cost-effective energy efficiency measures that could be
5implemented, by customer class, absent the limitations set
6forth in subsection (d) of Section 8-103. In seeking public
7comment on the electric utility's plan pursuant to subsection
8(g) (f) of Section 8-103, the Commission shall include,
9beginning in 2013, the assessment of additional cost-effective
10energy efficiency measures submitted pursuant to this Section.
11For purposes of this Section, the term "energy efficiency"
12shall have the meaning set forth in Section 1-10 of the
13Illinois Power Agency Act, and the term "cost-effective" shall
14have the meaning set forth in subsection (a) of Section 8-103
15of this Act.
16(Source: P.A. 97-616, eff. 10-26-11.)
 
17    (220 ILCS 5/8-104)
18    Sec. 8-104. Natural gas energy efficiency programs.
19    (a) It is the policy of the State that natural gas
20utilities and the Department of Commerce and Economic
21Opportunity are required to use cost-effective energy
22efficiency to reduce direct and indirect costs to consumers. It
23serves the public interest to allow natural gas utilities to
24recover costs for reasonably and prudently incurred expenses
25for cost-effective energy efficiency measures.

 

 

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1    (b) For purposes of this Section, "energy efficiency" means
2measures that reduce the amount of energy required to achieve a
3given end use. "Energy efficiency" also includes measures that
4reduce the total Btus of electricity and natural gas needed to
5meet the end use or uses. "Cost-effective" means that the
6measures satisfy the total resource cost test which, for
7purposes of this Section, means a standard that is met if, for
8an investment in energy efficiency, the benefit-cost ratio is
9greater than one. The benefit-cost ratio is the ratio of the
10net present value of the total benefits of the measures to the
11net present value of the total costs as calculated over the
12lifetime of the measures. The total resource cost test compares
13the sum of avoided natural gas utility costs, representing the
14benefits that accrue to the system and the participant in the
15delivery of those efficiency measures, as well as other
16quantifiable societal benefits, including avoided electric
17utility costs, to the sum of all incremental costs of end use
18measures (including both utility and participant
19contributions), plus costs to administer, deliver, and
20evaluate each demand-side measure, to quantify the net savings
21obtained by substituting demand-side measures for supply
22resources. In calculating avoided costs, reasonable estimates
23shall be included for financial costs likely to be imposed by
24future regulation of emissions of greenhouse gases. The
25low-income programs described in item (4) of subsection (f) of
26this Section shall not be required to meet the total resource

 

 

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1cost test.
2    (c) Natural gas utilities shall implement cost-effective
3energy efficiency measures to meet at least the following
4natural gas savings requirements, which shall be based upon the
5total amount of gas delivered to retail customers, other than
6the customers described in subsection (m) of this Section,
7during calendar year 2009 multiplied by the applicable
8percentage. Natural gas utilities may comply with this Section
9by meeting the annual incremental savings goal in the
10applicable year or by showing that total cumulative annual
11savings within a multi-year 3-year planning period associated
12with measures implemented after May 31, 2011 were equal to the
13sum of each annual incremental savings requirement from the
14first day of the multi-year planning period May 31, 2011
15through the last day of the multi-year planning period end of
16the applicable year:
17        (1) 0.2% by May 31, 2012;
18        (2) an additional 0.4% by May 31, 2013, increasing
19    total savings to .6%;
20        (3) an additional 0.6% by May 31, 2014, increasing
21    total savings to 1.2%;
22        (4) an additional 0.8% by May 31, 2015, increasing
23    total savings to 2.0%;
24        (5) an additional 1% by May 31, 2016, increasing total
25    savings to 3.0%;
26        (6) an additional 1.2% by May 31, 2017, increasing

 

 

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1    total savings to 4.2%;
2        (7) an additional 1.4% in the year commencing January
3    1, 2018 by May 31, 2018, increasing total savings to 5.6%;
4        (8) an additional 1.5% in the year commencing January
5    1, 2019 by May 31, 2019, increasing total savings to 7.1%;
6    and
7        (9) an additional 1.5% in each 12-month period
8    thereafter.
9    (d) Notwithstanding the requirements of subsection (c) of
10this Section, a natural gas utility shall limit the amount of
11energy efficiency implemented in any multi-year 3-year
12reporting period established by subsection (f) of Section 8-104
13of this Act, by an amount necessary to limit the estimated
14average increase in the amounts paid by retail customers in
15connection with natural gas service to no more than 2% in the
16applicable multi-year 3-year reporting period. The energy
17savings requirements in subsection (c) of this Section may be
18reduced by the Commission for the subject plan, if the utility
19demonstrates by substantial evidence that it is highly unlikely
20that the requirements could be achieved without exceeding the
21applicable spending limits in any multi-year 3-year reporting
22period. No later than September 1, 2013, the Commission shall
23review the limitation on the amount of energy efficiency
24measures implemented pursuant to this Section and report to the
25General Assembly, in the report required by subsection (k) of
26this Section, its findings as to whether that limitation unduly

 

 

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1constrains the procurement of energy efficiency measures.
2    (e) Natural gas utilities shall be responsible for
3overseeing the design, development, and filing of their
4efficiency plans with the Commission. The utility shall utilize
575% of the available funding associated with energy efficiency
6programs approved by the Commission, and may outsource various
7aspects of program development and implementation. The
8remaining 25% of available funding shall be used by the
9Department of Commerce and Economic Opportunity to implement
10energy efficiency measures that achieve no less than 20% of the
11requirements of subsection (c) of this Section. Such measures
12shall be designed in conjunction with the utility and approved
13by the Commission. The Department may outsource development and
14implementation of energy efficiency measures. A minimum of 10%
15of the entire portfolio of cost-effective energy efficiency
16measures shall be procured from local government, municipal
17corporations, school districts, and community college
18districts. Five percent of the entire portfolio of
19cost-effective energy efficiency measures may be granted to
20local government and municipal corporations for market
21transformation initiatives. The Department shall coordinate
22the implementation of these measures and, until December 31,
232017, shall integrate delivery of natural gas efficiency
24programs with electric efficiency programs delivered pursuant
25to Section 8-103 of this Act, unless the Department can show
26that integration is not feasible.

 

 

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1    The apportionment of the dollars to cover the costs to
2implement the Department's share of the portfolio of energy
3efficiency measures shall be made to the Department once the
4Department has executed rebate agreements, grants, or
5contracts for energy efficiency measures and provided
6supporting documentation for those rebate agreements, grants,
7and contracts to the utility. The Department is authorized to
8adopt any rules necessary and prescribe procedures in order to
9ensure compliance by applicants in carrying out the purposes of
10rebate agreements for energy efficiency measures implemented
11by the Department made under this Section.
12    The details of the measures implemented by the Department
13shall be submitted by the Department to the Commission in
14connection with the utility's filing regarding the energy
15efficiency measures that the utility implements.
16    A utility providing approved energy efficiency measures in
17this State shall be permitted to recover costs of those
18measures through an automatic adjustment clause tariff filed
19with and approved by the Commission. The tariff shall be
20established outside the context of a general rate case and
21shall be applicable to the utility's customers other than the
22customers described in subsection (m) of this Section. Each
23year the Commission shall initiate a review to reconcile any
24amounts collected with the actual costs and to determine the
25required adjustment to the annual tariff factor to match annual
26expenditures.

 

 

09900HB3328ham001- 95 -LRB099 10473 MLM 33016 a

1    Each utility shall include, in its recovery of costs, the
2costs estimated for both the utility's and the Department's
3implementation of energy efficiency measures. Costs collected
4by the utility for measures implemented by the Department shall
5be submitted to the Department pursuant to Section 605-323 of
6the Civil Administrative Code of Illinois, shall be deposited
7into the Energy Efficiency Portfolio Standards Fund, and shall
8be used by the Department solely for the purpose of
9implementing these measures. A utility shall not be required to
10advance any moneys to the Department but only to forward such
11funds as it has collected. The Department shall report to the
12Commission on an annual basis regarding the costs actually
13incurred by the Department in the implementation of the
14measures. Any changes to the costs of energy efficiency
15measures as a result of plan modifications shall be
16appropriately reflected in amounts recovered by the utility and
17turned over to the Department.
18    The portfolio of measures, administered by both the
19utilities and the Department, shall, in combination, be
20designed to achieve the annual energy savings requirements set
21forth in subsection (c) of this Section, as modified by
22subsection (d) of this Section.
23    The utility and the Department shall agree upon a
24reasonable portfolio of measures and determine the measurable
25corresponding percentage of the savings goals associated with
26measures implemented by the Department.

 

 

09900HB3328ham001- 96 -LRB099 10473 MLM 33016 a

1    No utility shall be assessed a penalty under subsection (f)
2of this Section for failure to make a timely filing if that
3failure is the result of a lack of agreement with the
4Department with respect to the allocation of responsibilities
5or related costs or target assignments. In that case, the
6Department and the utility shall file their respective plans
7with the Commission and the Commission shall determine an
8appropriate division of measures and programs that meets the
9requirements of this Section.
10    If the Department is unable to meet performance
11requirements for the portion of the portfolio implemented by
12the Department, then the utility and the Department shall
13jointly submit a modified filing to the Commission explaining
14the performance shortfall and recommending an appropriate
15course going forward, including any program modifications that
16may be appropriate in light of the evaluations conducted under
17item (8) of subsection (f) of this Section. In this case, the
18utility obligation to collect the Department's costs and turn
19over those funds to the Department under this subsection (e)
20shall continue only if the Commission approves the
21modifications to the plan proposed by the Department.
22    (f) No later than October 1, 2010, each gas utility shall
23file an energy efficiency plan with the Commission to meet the
24energy efficiency standards through May 31, 2014. No later than
25October 1, 2013, each gas utility shall file an energy
26efficiency plan with the Commission to meet the energy

 

 

09900HB3328ham001- 97 -LRB099 10473 MLM 33016 a

1efficiency standards through May 31, 2017. Beginning March 1,
22017 and every 4 Every 3 years thereafter, each utility shall
3file, no later than October 1, an energy efficiency plan with
4the Commission to meet the energy efficiency standards for the
5applicable 4-year period. If a utility does not file such a
6plan by March October 1 of the applicable year, then it shall
7face a penalty of $100,000 per day until the plan is filed.
8Each utility's plan shall set forth the utility's proposals to
9meet the utility's portion of the energy efficiency standards
10identified in subsection (c) of this Section, as modified by
11subsection (d) of this Section, taking into account the unique
12circumstances of the utility's service territory. The
13Commission shall seek public comment on the utility's plan and
14shall issue an order approving or disapproving each plan within
156 months after its submission. If the Commission disapproves a
16plan, the Commission shall, within 30 days, describe in detail
17the reasons for the disapproval and describe a path by which
18the utility may file a revised draft of the plan to address the
19Commission's concerns satisfactorily. If the utility does not
20refile with the Commission within 60 days after the
21disapproval, the utility shall be subject to penalties at a
22rate of $100,000 per day until the plan is filed. This process
23shall continue, and penalties shall accrue, until the utility
24has successfully filed a portfolio of energy efficiency
25measures. Penalties shall be deposited into the Energy
26Efficiency Trust Fund and the cost of any such penalties may

 

 

09900HB3328ham001- 98 -LRB099 10473 MLM 33016 a

1not be recovered from ratepayers. In submitting proposed energy
2efficiency plans and funding levels to meet the savings goals
3adopted by this Act the utility shall:
4        (1) Demonstrate that its proposed energy efficiency
5    measures will achieve the requirements that are identified
6    in subsection (c) of this Section, as modified by
7    subsection (d) of this Section.
8        (2) Present specific proposals to implement new
9    building and appliance standards that have been placed into
10    effect.
11        (3) Present estimates of the total amount paid for gas
12    service expressed on a per therm basis associated with the
13    proposed portfolio of measures designed to meet the
14    requirements that are identified in subsection (c) of this
15    Section, as modified by subsection (d) of this Section.
16        (4) Coordinate with the Department to present a
17    portfolio of energy efficiency measures proportionate to
18    the share of total annual utility revenues in Illinois from
19    households at or below 150% of the poverty level. Such
20    programs shall be targeted to households with incomes at or
21    below 80% of area median income.
22        (5) Demonstrate that its overall portfolio of energy
23    efficiency measures, not including programs covered by
24    item (4) of this subsection (f), are cost-effective using
25    the total resource cost test and represent a diverse cross
26    section of opportunities for customers of all rate classes

 

 

09900HB3328ham001- 99 -LRB099 10473 MLM 33016 a

1    to participate in the programs.
2        (6) Demonstrate that a gas utility affiliated with an
3    electric utility that is required to comply with Section
4    8-103 of this Act has integrated gas and electric
5    efficiency measures into a single program that reduces
6    program or participant costs and appropriately allocates
7    costs to gas and electric ratepayers. The Department shall
8    integrate all gas and electric programs it delivers in any
9    such utilities' service territories, unless the Department
10    can show that integration is not feasible or appropriate.
11        (7) Include a proposed cost recovery tariff mechanism
12    to fund the proposed energy efficiency measures and to
13    ensure the recovery of the prudently and reasonably
14    incurred costs of Commission-approved programs.
15        (8) Provide for quarterly status reports tracking
16    implementation of and expenditures for the utility's
17    portfolio of measures and the Department's portfolio of
18    measures, an annual independent review, and a full
19    independent evaluation of the multi-year 3-year results of
20    the performance and the cost-effectiveness of the
21    utility's and Department's portfolios of measures and
22    broader net program impacts and, to the extent practical,
23    for adjustment of the measures on a going forward basis as
24    a result of the evaluations. The resources dedicated to
25    evaluation shall not exceed 3% of portfolio resources in
26    any given multi-year 3-year period.

 

 

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1    (g) No more than 3% of expenditures on energy efficiency
2measures may be allocated for demonstration of breakthrough
3equipment and devices.
4    (h) Illinois natural gas utilities that are affiliated by
5virtue of a common parent company may, at the utilities'
6request, be considered a single natural gas utility for
7purposes of complying with this Section.
8    (i) If, after 3 years, a gas utility fails to meet the
9efficiency standard specified in subsection (c) of this Section
10as modified by subsection (d), then it shall make a
11contribution to the Low-Income Home Energy Assistance Program.
12The total liability for failure to meet the goal shall be
13assessed as follows:
14        (1) a large gas utility shall pay $600,000;
15        (2) a medium gas utility shall pay $400,000; and
16        (3) a small gas utility shall pay $200,000.
17    For purposes of this Section, (i) a "large gas utility" is
18a gas utility that on December 31, 2008, served more than
191,500,000 gas customers in Illinois; (ii) a "medium gas
20utility" is a gas utility that on December 31, 2008, served
21fewer than 1,500,000, but more than 500,000 gas customers in
22Illinois; and (iii) a "small gas utility" is a gas utility that
23on December 31, 2008, served fewer than 500,000 and more than
24100,000 gas customers in Illinois. The costs of this
25contribution may not be recovered from ratepayers.
26    If a gas utility fails to meet the efficiency standard

 

 

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1specified in subsection (c) of this Section, as modified by
2subsection (d) of this Section, in any 2 consecutive 3-year
3planning periods, then the responsibility for implementing the
4utility's energy efficiency measures shall be transferred to an
5independent program administrator selected by the Commission.
6Reasonable and prudent costs incurred by the independent
7program administrator to meet the efficiency standard
8specified in subsection (c) of this Section, as modified by
9subsection (d) of this Section, may be recovered from the
10customers of the affected gas utilities, other than customers
11described in subsection (m) of this Section. The utility shall
12provide the independent program administrator with all
13information and assistance necessary to perform the program
14administrator's duties including but not limited to customer,
15account, and energy usage data, and shall allow the program
16administrator to include inserts in customer bills. The utility
17may recover reasonable costs associated with any such
18assistance.
19    (j) No utility shall be deemed to have failed to meet the
20energy efficiency standards to the extent any such failure is
21due to a failure of the Department.
22    (k) Not later than January 1, 2012, the Commission shall
23develop and solicit public comment on a plan to foster
24statewide coordination and consistency between statutorily
25mandated natural gas and electric energy efficiency programs to
26reduce program or participant costs or to improve program

 

 

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1performance. Not later than September 1, 2013, the Commission
2shall issue a report to the General Assembly containing its
3findings and recommendations.
4    (l) This Section does not apply to a gas utility that on
5January 1, 2009, provided gas service to fewer than 100,000
6customers in Illinois.
7    (m) Subsections (a) through (k) of this Section do not
8apply to customers of a natural gas utility that have a North
9American Industry Classification System code number that is
1022111 or any such code number beginning with the digits 31, 32,
11or 33 and (i) annual usage in the aggregate of 4 million therms
12or more within the service territory of the affected gas
13utility or with aggregate usage of 8 million therms or more in
14this State and complying with the provisions of item (l) of
15this subsection (m); or (ii) using natural gas as feedstock and
16meeting the usage requirements described in item (i) of this
17subsection (m), to the extent such annual feedstock usage is
18greater than 60% of the customer's total annual usage of
19natural gas.
20        (1) Customers described in this subsection (m) of this
21    Section shall apply, on a form approved on or before
22    October 1, 2009 by the Department, to the Department to be
23    designated as a self-directing customer ("SDC") or as an
24    exempt customer using natural gas as a feedstock from which
25    other products are made, including, but not limited to,
26    feedstock for a hydrogen plant, on or before the 1st day of

 

 

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1    February, 2010. Thereafter, application may be made not
2    less than 6 months before the filing date of the gas
3    utility energy efficiency plan described in subsection (f)
4    of this Section; however, a new customer that commences
5    taking service from a natural gas utility after February 1,
6    2010 may apply to become a SDC or exempt customer up to 30
7    days after beginning service. Customers described in this
8    subsection (m) that have not already been approved by the
9    Department may apply to be designated a self-directing
10    customer or exempt customer, on a form approved by the
11    Department, between September 1, 2013 and September 30,
12    2013. Customer applications that are approved by the
13    Department under this amendatory Act of the 98th General
14    Assembly shall be considered to be a self-directing
15    customer or exempt customer, as applicable, for the current
16    3-year planning period effective December 1, 2013. Such
17    application shall contain the following:
18            (A) the customer's certification that, at the time
19        of its application, it qualifies to be a SDC or exempt
20        customer described in this subsection (m) of this
21        Section;
22            (B) in the case of a SDC, the customer's
23        certification that it has established or will
24        establish by the beginning of the utility's 3-year
25        planning period commencing subsequent to the
26        application, and will maintain for accounting

 

 

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1        purposes, an energy efficiency reserve account and
2        that the customer will accrue funds in said account to
3        be held for the purpose of funding, in whole or in
4        part, energy efficiency measures of the customer's
5        choosing, which may include, but are not limited to,
6        projects involving combined heat and power systems
7        that use the same energy source both for the generation
8        of electrical or mechanical power and the production of
9        steam or another form of useful thermal energy or the
10        use of combustible gas produced from biomass, or both;
11            (C) in the case of a SDC, the customer's
12        certification that annual funding levels for the
13        energy efficiency reserve account will be equal to 2%
14        of the customer's cost of natural gas, composed of the
15        customer's commodity cost and the delivery service
16        charges paid to the gas utility, or $150,000, whichever
17        is less;
18            (D) in the case of a SDC, the customer's
19        certification that the required reserve account
20        balance will be capped at 3 years' worth of accruals
21        and that the customer may, at its option, make further
22        deposits to the account to the extent such deposit
23        would increase the reserve account balance above the
24        designated cap level;
25            (E) in the case of a SDC, the customer's
26        certification that by October 1 of each year, beginning

 

 

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1        no sooner than October 1, 2012, the customer will
2        report to the Department information, for the 12-month
3        period ending May 31 of the same year, on all deposits
4        and reductions, if any, to the reserve account during
5        the reporting year, and to the extent deposits to the
6        reserve account in any year are in an amount less than
7        $150,000, the basis for such reduced deposits; reserve
8        account balances by month; a description of energy
9        efficiency measures undertaken by the customer and
10        paid for in whole or in part with funds from the
11        reserve account; an estimate of the energy saved, or to
12        be saved, by the measure; and that the report shall
13        include a verification by an officer or plant manager
14        of the customer or by a registered professional
15        engineer or certified energy efficiency trade
16        professional that the funds withdrawn from the reserve
17        account were used for the energy efficiency measures;
18            (F) in the case of an exempt customer, the
19        customer's certification of the level of gas usage as
20        feedstock in the customer's operation in a typical year
21        and that it will provide information establishing this
22        level, upon request of the Department;
23            (G) in the case of either an exempt customer or a
24        SDC, the customer's certification that it has provided
25        the gas utility or utilities serving the customer with
26        a copy of the application as filed with the Department;

 

 

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1            (H) in the case of either an exempt customer or a
2        SDC, certification of the natural gas utility or
3        utilities serving the customer in Illinois including
4        the natural gas utility accounts that are the subject
5        of the application; and
6            (I) in the case of either an exempt customer or a
7        SDC, a verification signed by a plant manager or an
8        authorized corporate officer attesting to the
9        truthfulness and accuracy of the information contained
10        in the application.
11        (2) The Department shall review the application to
12    determine that it contains the information described in
13    provisions (A) through (I) of item (1) of this subsection
14    (m), as applicable. The review shall be completed within 30
15    days after the date the application is filed with the
16    Department. Absent a determination by the Department
17    within the 30-day period, the applicant shall be considered
18    to be a SDC or exempt customer, as applicable, for all
19    subsequent multi-year 3-year planning periods, as of the
20    date of filing the application described in this subsection
21    (m). If the Department determines that the application does
22    not contain the applicable information described in
23    provisions (A) through (I) of item (1) of this subsection
24    (m), it shall notify the customer, in writing, of its
25    determination that the application does not contain the
26    required information and identify the information that is

 

 

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1    missing, and the customer shall provide the missing
2    information within 15 working days after the date of
3    receipt of the Department's notification.
4        (3) The Department shall have the right to audit the
5    information provided in the customer's application and
6    annual reports to ensure continued compliance with the
7    requirements of this subsection. Based on the audit, if the
8    Department determines the customer is no longer in
9    compliance with the requirements of items (A) through (I)
10    of item (1) of this subsection (m), as applicable, the
11    Department shall notify the customer in writing of the
12    noncompliance. The customer shall have 30 days to establish
13    its compliance, and failing to do so, may have its status
14    as a SDC or exempt customer revoked by the Department. The
15    Department shall treat all information provided by any
16    customer seeking SDC status or exemption from the
17    provisions of this Section as strictly confidential.
18        (4) Upon request, or on its own motion, the Commission
19    may open an investigation, no more than once every 3 years
20    and not before October 1, 2014, to evaluate the
21    effectiveness of the self-directing program described in
22    this subsection (m).
23    Customers described in this subsection (m) that applied to
24the Department on January 3, 2013, were approved by the
25Department on February 13, 2013 to be a self-directing customer
26or exempt customer, and receive natural gas from a utility that

 

 

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1provides gas service to at least 500,000 retail customers in
2Illinois and electric service to at least 1,000,000 retail
3customers in Illinois shall be considered to be a
4self-directing customer or exempt customer, as applicable, for
5the current 3-year planning period effective December 1, 2013.
6    (n) The applicability of this Section to customers
7described in subsection (m) of this Section is conditioned on
8the existence of the SDC program. In no event will any
9provision of this Section apply to such customers after January
101, 2020.
11    (o) Utilities' 3-year energy efficiency plans approved by
12the Commission on or before the effective date of this
13amendatory Act of the 99th General Assembly for the period June
141, 2014 through May 31, 2017 shall continue to be in force and
15effect through December 31, 2017 so that the energy efficiency
16programs set forth in those plans continue to be offered during
17the period June 1, 2017 through December 31, 2017. Each utility
18is authorized to increase, on a pro-rata basis, the energy
19savings goals and budgets approved in its plan to reflect the
20additional 7 months of the plan's operation.
21(Source: P.A. 97-813, eff. 7-13-12; 97-841, eff. 7-20-12;
2298-90, eff. 7-15-13; 98-225, eff. 8-9-13; 98-604, eff.
2312-17-13.)
 
24    (220 ILCS 5/9-105 new)
25    Sec. 9-105. Demand-based delivery services charge.

 

 

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1Beginning with the January 2018 monthly billing period, an
2electric utility that serves more than 3,000,000 retail
3customers in the State may recover its costs of providing
4delivery services to retail customers as follows:
5        (1) the categories of costs being recovered through a
6    fixed charge on the effective date of this amendatory Act
7    of the 99th General Assembly shall continue to be recovered
8    through a fixed charge;
9        (2) costs being recovered through riders on the
10    effective date of this amendatory Act of the 99th General
11    Assembly and add-on taxes and other separately-stated
12    charges or adjustments shall continue to be recovered in
13    the manner they are being collected, provided that nothing
14    in this paragraph (2) shall prohibit addition or
15    elimination of a rider or preclude the utility from
16    revising those riders, pursuant to this Article IX and any
17    applicable provisions of this Act, regardless of whether
18    such riders assess charges on a kilowatt-hour or kilowatt
19    basis;
20        (3) taxes incurred pursuant to the Public Utilities
21    Revenue Act shall continue to be recovered on a
22    kilowatt-hour basis; and
23        (4) all remaining costs of providing delivery services
24    to retail customers shall be recovered through a charge
25    based on kilowatts of demand.
26    A utility shall file tariffs implementing the provisions of

 

 

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1this Section pursuant to Section 9-201 of this Act, provided
2that a participating utility as defined in Section 16-108.5 of
3this Act shall file such tariffs pursuant to subsection (e) of
4Section 16-108.5.
5    An electric utility may estimate retail customers'
6kilowatt demands if the interval data necessary to determine
7such customers' kilowatt demands is not available.
 
8    (220 ILCS 5/9-106 new)
9    Sec. 9-106. Electric utility line extensions; distribution
10capacity expansion.
11    (a) The General Assembly finds that it is a goal of this
12State to encourage the establishment of new businesses and
13expansion of existing businesses in Illinois and further finds
14that start-up costs may be a significant obstacle, and at times
15a deterrent, to undertaking new investment in Illinois. In
16light of the economy's increasing reliance on electricity to
17fuel business, technology, and innovation, the General
18Assembly finds that it is appropriate for the State's electric
19utilities to now undertake a review of their tariffs that
20impact such start-up costs.
21    (b) Each electric utility serving more than 200,000
22customers in Illinois on the effective date of this amendatory
23Act of the 99th General Assembly shall review its tariffs
24relating to line extensions and distribution capacity
25expansion. Following such a review, the utility may file tariff

 

 

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1changes with the Commission that are consistent with the
2objectives described in subsection (a) of this Section. Such
3tariffs shall be submitted to the Commission under Section
49-201 of this Act, except that the Commission shall approve, or
5modify and approve, such tariffs within 120 days after the date
6on which they are filed. The Commission shall review its rules
7relating to utility line extensions and distribution capacity
8expansion to be consistent with any tariffs approved pursuant
9to this Section.
 
10    (220 ILCS 5/16-103.3 new)
11    Sec. 16-103.3. Unbundling of charges related to
12electricity supply and regional transmission organization
13services. Beginning with the January 2018 monthly billing
14period, an electric utility that provides electric service to
15more than 3,000,000 retail customers in the State shall
16restructure its retail electricity supply charges applicable
17to eligible retail customers, as defined by Section 16-111.5 of
18this Act, for whom the electric utility procures electric power
19and energy pursuant to Section 1-75 of the Illinois Power
20Agency Act and Section 16-111.5 of this Act. The restructuring
21shall separately recover the costs of electric capacity and
22other services incurred by the electric utility related to
23providing electricity supply where such costs are not primarily
24incurred based upon the number of kilowatt-hours consumed.
25Charges that recover the costs shall appear as 2 separate line

 

 

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1items on the eligible retail customers' electric service bills.
2The costs shall not be included in the costs of determining the
3kilowatt-hour based electricity supply charges for electric
4power and energy and shall be recovered through separate
5kilowatt-based charges applicable to customers' kilowatt
6demands.
7    In addition to the costs of electric capacity, an electric
8utility shall also recover the costs of services it procures
9from the regional transmission organization of which it is a
10member, including, but not limited to, the transmission and
11ancillary transmission services costs that are not primarily
12incurred on a kilowatt-hour basis, from eligible retail
13customers through kilowatt-based charges applicable to the
14customers' kilowatt demands and not through kilowatt-hour
15based charges.
16    An electric utility may estimate eligible retail
17customers' kilowatt demands if the interval data necessary to
18determine such customers' kilowatt demands is not available.
19    It is the intent of this Section that eligible retail
20customers taking electricity supply service from such electric
21utility pay kilowatt-based charges for the electricity supply
22and regional transmission organization-related services costs
23that are not primarily incurred on a kilowatt-hour basis.
 
24    (220 ILCS 5/16-103.4 new)
25    Sec. 16-103.4. Demand-response facilitation service.

 

 

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1    (a) It is a policy of this State to promote investment in
2demand-response resources. The General Assembly has previously
3found that including cost-effective demand-response resources
4in a diverse electricity supply portfolio will reduce long-term
5direct and indirect costs to consumers by decreasing
6environmental impacts and by avoiding or delaying the need for
7new generation, transmission, and distribution infrastructure.
8The General Assembly finds, however, that recent legal
9developments affecting the regional transmission organizations
10that serve Illinois have altered the way in which
11demand-response resources can be procured and present new
12obstacles to the continued procurement of cost-effective
13demand-response resources.
14    The General Assembly further finds that on January 14,
152015, PJM Interconnection, the regional transmission
16organization serving most of the State's retail customers,
17filed a tariff with the Federal Energy Regulatory Commission
18that would provide an alternative path by which states could
19continue to procure demand-response resources.
20    To ensure that the State's policy regarding procurement of
21demand-response resources continues to be implemented, an
22electric utility providing service to more than 3,000,000
23customers in the State may participate in an auction as
24authorized by the tariff, provided that the tariff is lawfully
25placed into effect. A utility that elects to participate may
26recover its costs as specified in this Section.

 

 

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1    (b) In the event the tariff described in subsection (a) of
2this Section is lawfully placed into effect, an electric
3utility serving more than 3,000,000 retail customers in the
4State may facilitate the continued procurement of
5demand-response resources from its retail customers. As part of
6such procurement, the electric utility may contract with
7curtailment service providers and load serving entities to
8procure demand-response resources from the utility's retail
9customers, which the utility may use to submit demand-response
10bids through the utility's account into the Reliability Pricing
11Model auction. All of the costs the electric utility incurs to
12implement this program, including compensating the curtailment
13service providers and load serving entities for the
14demand-response bids that clear the auction and for which the
15utility is obligated, shall be recovered from all of its retail
16customers through a non-bypassable charge applied to their
17electric bills. The electric utility shall recover such costs
18through an automatic adjustment clause tariff, which may be
19filed and established outside the context of a general rate
20case filing or a filing under subsections (c) or (d) of Section
2116-108.5 of this Act. The Commission shall review and, after
22notice and hearing, by order approve or approve with
23modification the proposed tariff no later than 180 days after
24the filing of the tariff. A tariff approved and placed into
25effect pursuant to this Section shall remain in effect at the
26discretion of the utility, and the utility may withdraw the

 

 

09900HB3328ham001- 115 -LRB099 10473 MLM 33016 a

1tariff at any time. Each year the Commission shall initiate a
2proceeding to review and reconcile any amounts collected with
3the actual costs.
 
4    (220 ILCS 5/16-107)
5    Sec. 16-107. Real-time pricing.
6    (a) Each electric utility shall file, on or before May 1,
71998, a tariff or tariffs which allow nonresidential retail
8customers in the electric utility's service area to elect
9real-time pricing beginning October 1, 1998.
10    (b) Each electric utility shall file, on or before May 1,
112000, a tariff or tariffs which allow residential retail
12customers in the electric utility's service area to elect
13real-time pricing beginning October 1, 2000.
14    (b-5) Each electric utility shall file a tariff or tariffs
15allowing residential retail customers in the electric
16utility's service area to elect real-time pricing beginning
17January 2, 2007. The Commission may, after notice and hearing,
18approve the tariff or tariffs. A customer who elects real-time
19pricing shall remain on such rate for a minimum of 12 months.
20The Commission may, after notice and hearing, approve the
21tariff or tariffs, provided that the Commission finds that the
22potential for demand reductions will result in net economic
23benefits to all residential customers of the electric utility.
24In examining economic benefits from demand reductions, the
25Commission shall, at a minimum, consider the following:

 

 

09900HB3328ham001- 116 -LRB099 10473 MLM 33016 a

1improvements to system reliability and power quality,
2reduction in wholesale market prices and price volatility,
3electric utility cost avoidance and reductions, market power
4mitigation, and other benefits of demand reductions, but only
5to the extent that the effects of reduced demand can be
6demonstrated to lower the cost of electricity delivered to
7residential customers. A tariff or tariffs approved pursuant to
8this subsection (b-5) shall, at a minimum, describe (i) the
9methodology for determining the market price of energy to be
10reflected in the real-time rate and (ii) the manner in which
11customers who elect real-time pricing will be provided with
12ready access to hourly market prices, including, but not
13limited to, day-ahead hourly energy prices. A customer who
14elects real-time pricing pursuant to a tariff approved under
15this Section and thereafter terminates the election shall not
16return to taking service under the tariff for a period of 12
17months following the date on which the customer terminated
18real-time pricing.
19    A proceeding under this subsection (b-5) may not exceed 120
20days in length.
21    (b-10) Each electric utility providing real-time pricing
22pursuant to subsection (b-5) shall install a meter capable of
23recording hourly interval energy use at the service location of
24each customer that elects real-time pricing pursuant to this
25subsection.
26    (b-15) If the Commission issues an order pursuant to

 

 

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1subsection (b-5), the affected electric utility shall contract
2with an entity not affiliated with the electric utility to
3serve as a program administrator to develop and implement a
4program to provide consumer outreach, enrollment, and
5education concerning real-time pricing and to establish and
6administer an information system and technical and other
7customer assistance that is necessary to enable customers to
8manage electricity use. The program administrator: (i) shall be
9selected and compensated by the electric utility, subject to
10Commission approval; (ii) shall have demonstrated technical
11and managerial competence in the development and
12administration of demand management programs; and (iii) may
13develop and implement risk management, energy efficiency, and
14other services related to energy use management for which the
15program administrator shall be compensated by participants in
16the program receiving such services. The electric utility shall
17provide the program administrator with all information and
18assistance necessary to perform the program administrator's
19duties, including, but not limited to, customer, account, and
20energy use data. The electric utility shall permit the program
21administrator to include inserts in residential customer bills
222 times per year to assist with customer outreach and
23enrollment.
24    The program administrator shall submit an annual report to
25the electric utility no later than April 1 of each year
26describing the operation and results of the program, including

 

 

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1information concerning the number and types of customers using
2real-time pricing, changes in customers' energy use patterns,
3an assessment of the value of the program to both participants
4and non-participants, and recommendations concerning
5modification of the program and the tariff or tariffs filed
6under subsection (b-5). This report shall be filed by the
7electric utility with the Commission within 30 days of receipt
8and shall be available to the public on the Commission's web
9site.
10    (b-20) The Commission shall monitor the performance of
11programs established pursuant to subsection (b-15) and shall
12order the termination or modification of a program if it
13determines that the program is not, after a reasonable period
14of time for development not to exceed 4 years after the
15effective date of this amendatory Act of the 99th General
16Assembly, resulting in net benefits to the residential
17customers of the electric utility.
18    (b-25) An electric utility shall be entitled to recover
19reasonable costs incurred in complying with this Section,
20provided that recovery of the costs is fairly apportioned among
21its residential customers as provided in this subsection
22(b-25). The electric utility may apportion greater costs on the
23residential customers who elect real-time pricing, but may also
24impose some of the costs of real-time pricing on customers who
25do not elect real-time pricing, provided that the Commission
26determines that the cost savings resulting from real-time

 

 

09900HB3328ham001- 119 -LRB099 10473 MLM 33016 a

1pricing will exceed the costs imposed on customers for
2maintaining the program.
3    (c) The electric utility's tariff or tariffs filed pursuant
4to this Section shall be subject to Article IX.
5    (d) This Section does not apply to any electric utility
6providing service to 100,000 or fewer customers.
7(Source: P.A. 94-977, eff. 6-30-06.)
 
8    (220 ILCS 5/16-107.5)
9    Sec. 16-107.5. Net electricity metering.
10    (a) The Legislature finds and declares that a program to
11provide net electricity metering, as defined in this Section,
12for eligible customers can encourage private investment in
13renewable energy resources, stimulate economic growth, enhance
14the continued diversification of Illinois' energy resource
15mix, and protect the Illinois environment.
16    (b) As used in this Section, (i) "eligible customer" means
17a retail customer that owns or operates a solar, wind, or other
18eligible renewable electrical generating facility with a rated
19capacity of not more than 2,000 kilowatts that is located on
20the customer's premises and is intended primarily to offset the
21customer's own electrical requirements; (ii) "electricity
22provider" means an electric utility or alternative retail
23electric supplier; (iii) "eligible renewable electrical
24generating facility" means a generator powered by solar
25electric energy, wind, dedicated crops grown for electricity

 

 

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1generation, agricultural residues, untreated and unadulterated
2wood waste, landscape trimmings, livestock manure, anaerobic
3digestion of livestock or food processing waste, fuel cells or
4microturbines powered by renewable fuels, or hydroelectric
5energy; and (iv) "net electricity metering" (or "net metering")
6means the measurement, during the billing period applicable to
7an eligible customer, of the net amount of electricity supplied
8by an electricity provider to the customer's premises or
9provided to the electricity provider by the customer.
10    (c) A net metering facility shall be equipped with metering
11equipment that can measure the flow of electricity in both
12directions at the same rate.
13        (1) For eligible customers whose electric service has
14    not been declared competitive pursuant to Section 16-113 of
15    this Act as of July 1, 2011 and whose electric delivery
16    service is provided and measured on a kilowatt-hour basis
17    and electric supply service is not provided based on hourly
18    pricing, this shall typically be accomplished through use
19    of a single, bi-directional meter. If the eligible
20    customer's existing electric revenue meter does not meet
21    this requirement, the electricity provider shall arrange
22    for the local electric utility or a meter service provider
23    to install and maintain a new revenue meter at the
24    electricity provider's expense.
25        (2) For eligible customers whose electric service has
26    not been declared competitive pursuant to Section 16-113 of

 

 

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

 

 

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

 

 

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1    or the annualized period, any remaining credits in the
2    customer's account shall expire.
3    (d-5) An electricity provider shall measure and charge or
4credit for the net electricity supplied to eligible customers
5or provided by eligible customers whose electric service has
6not been declared competitive pursuant to Section 16-113 of
7this Act as of July 1, 2011 and whose electric delivery service
8is provided and measured on a kilowatt-hour basis and electric
9supply service is provided based on hourly pricing in the
10following manner:
11        (1) If the amount of electricity used by the customer
12    during any hourly period exceeds the amount of electricity
13    produced by the customer, the electricity provider shall
14    charge the customer for the net electricity supplied to and
15    used by the customer according to the terms of the contract
16    or tariff to which the same customer would be assigned to
17    or be eligible for if the customer was not a net metering
18    customer.
19        (2) If the amount of electricity produced by a customer
20    during any hourly period exceeds the amount of electricity
21    used by the customer during that hourly period, the energy
22    provider shall apply a credit for the net kilowatt-hours
23    produced in such period. The credit shall consist of an
24    energy credit and a delivery service credit. The energy
25    credit shall be valued at the same price per kilowatt-hour
26    as the electric service provider would charge for

 

 

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

 

 

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1    1:1 kilowatt-hour credit that reflects the kilowatt-hour
2    based charges in the customer's electric service rate to a
3    subsequent bill for service to the customer for the net
4    electricity supplied to the electricity provider. The
5    electricity provider shall continue to carry over any
6    excess kilowatt-hour credits earned and apply those
7    credits to subsequent billing periods to offset any
8    customer-generator consumption in those billing periods
9    until all credits are used or until the end of the
10    annualized period.
11        (3) At the end of the year or annualized over the
12    period that service is supplied by means of net metering,
13    or in the event that the retail customer terminates service
14    with the electricity provider prior to the end of the year
15    or the annualized period, any remaining credits in the
16    customer's account shall expire.
17    (e-5) An electricity provider shall provide electric
18service to eligible customers who utilize net metering at
19non-discriminatory rates that are identical, with respect to
20rate structure, retail rate components, and any monthly
21charges, to the rates that the customer would be charged if not
22a net metering customer. An electricity provider shall not
23charge net metering customers any fee or charge or require
24additional equipment, insurance, or any other requirements not
25specifically authorized by interconnection standards
26authorized by the Commission, unless the fee, charge, or other

 

 

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1requirement would apply to other similarly situated customers
2who are not net metering customers. The customer will remain
3responsible for all taxes, fees, and utility delivery charges
4that would otherwise be applicable to the net amount of
5electricity used by the customer. Subsections (c) through (e)
6of this Section shall not be construed to prevent an
7arms-length agreement between an electricity provider and an
8eligible customer that sets forth different prices, terms, and
9conditions for the provision of net metering service,
10including, but not limited to, the provision of the appropriate
11metering equipment for non-residential customers.
12    (f) Notwithstanding the requirements of subsections (c)
13through (e-5) of this Section, an electricity provider must
14require dual-channel metering for customers operating eligible
15renewable electrical generating facilities with a nameplate
16rating up to 2,000 kilowatts and to whom the provisions of
17neither subsection (d), (d-5), nor (e) of this Section apply.
18In such cases, electricity charges and credits shall be
19determined as follows:
20        (1) The electricity provider shall assess and the
21    customer remains responsible for all taxes, fees, and
22    utility delivery charges that would otherwise be
23    applicable to the gross amount of kilowatt-hours supplied
24    to the eligible customer by the electricity provider.
25        (2) Each month that service is supplied by means of
26    dual-channel metering, the electricity provider shall

 

 

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1    compensate the eligible customer for any excess
2    kilowatt-hour credits at the electricity provider's
3    avoided cost of electricity supply over the monthly period
4    or as otherwise specified by the terms of a power-purchase
5    agreement negotiated between the customer and electricity
6    provider.
7        (3) For all eligible net metering customers taking
8    service from an electricity provider under contracts or
9    tariffs employing time of use rates, any monthly
10    consumption of electricity shall be calculated according
11    to the terms of the contract or tariff to which the same
12    customer would be assigned to or be eligible for if the
13    customer was not a net metering customer. When those same
14    customer-generators are net generators during any discrete
15    time of use period, the net kilowatt-hours produced shall
16    be valued at the same price per kilowatt-hour as the
17    electric service provider would charge for retail
18    kilowatt-hour sales during that same time of use period.
19    (g) For purposes of federal and State laws providing
20renewable energy credits or greenhouse gas credits, the
21eligible customer shall be treated as owning and having title
22to the renewable energy attributes, renewable energy credits,
23and greenhouse gas emission credits related to any electricity
24produced by the qualified generating unit. The electricity
25provider may not condition participation in a net metering
26program on the signing over of a customer's renewable energy

 

 

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1credits; provided, however, this subsection (g) shall not be
2construed to prevent an arms-length agreement between an
3electricity provider and an eligible customer that sets forth
4the ownership or title of the credits.
5    (h) Within 120 days after the effective date of this
6amendatory Act of the 95th General Assembly, the Commission
7shall establish standards for net metering and, if the
8Commission has not already acted on its own initiative,
9standards for the interconnection of eligible renewable
10generating equipment to the utility system. The
11interconnection standards shall address any procedural
12barriers, delays, and administrative costs associated with the
13interconnection of customer-generation while ensuring the
14safety and reliability of the units and the electric utility
15system. The Commission shall consider the Institute of
16Electrical and Electronics Engineers (IEEE) Standard 1547 and
17the issues of (i) reasonable and fair fees and costs, (ii)
18clear timelines for major milestones in the interconnection
19process, (iii) nondiscriminatory terms of agreement, and (iv)
20any best practices for interconnection of distributed
21generation.
22    (i) All electricity providers shall begin to offer net
23metering no later than April 1, 2008. However, after December
2431, 2017, this Section shall not apply to an electric utility
25that serves more than 3,000,000 retail customers in the State.
26    (j) An electricity provider shall provide net metering to

 

 

09900HB3328ham001- 129 -LRB099 10473 MLM 33016 a

1eligible customers until the load of its net metering customers
2equals 5% of the total peak demand supplied by that electricity
3provider during the previous year. Electricity providers are
4authorized to offer net metering beyond the 5% level if they so
5choose.
6    (k) Each electricity provider shall maintain records and
7report annually to the Commission the total number of net
8metering customers served by the provider, as well as the type,
9capacity, and energy sources of the generating systems used by
10the net metering customers. Nothing in this Section shall limit
11the ability of an electricity provider to request the redaction
12of information deemed by the Commission to be confidential
13business information. Each electricity provider shall notify
14the Commission when the total generating capacity of its net
15metering customers is equal to or in excess of the 5% cap
16specified in subsection (j) of this Section.
17    (l) Notwithstanding the definition of "eligible customer"
18in item (i) of subsection (b) of this Section, each electricity
19provider shall consider whether to allow meter aggregation for
20the purposes of net metering on:
21        (1) properties owned or leased by multiple customers
22    that contribute to the operation of an eligible renewable
23    electrical generating facility, such as a community-owned
24    wind project, a community-owned biomass project, a
25    community-owned solar project, or a community methane
26    digester processing livestock waste from multiple sources;

 

 

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1    and
2        (2) individual units, apartments, or properties owned
3    or leased by multiple customers and collectively served by
4    a common eligible renewable electrical generating
5    facility, such as an apartment building served by
6    photovoltaic panels on the roof.
7    For the purposes of this subsection (l), "meter
8aggregation" means the combination of reading and billing on a
9pro rata basis for the types of eligible customers described in
10this Section.
11    (m) Nothing in this Section shall affect the right of an
12electricity provider to continue to provide, or the right of a
13retail customer to continue to receive service pursuant to a
14contract for electric service between the electricity provider
15and the retail customer in accordance with the prices, terms,
16and conditions provided for in that contract. Either the
17electricity provider or the customer may require compliance
18with the prices, terms, and conditions of the contract.
19(Source: P.A. 97-616, eff. 10-26-11; 97-646, eff. 12-30-11;
2097-824, eff. 7-18-12.)
 
21    (220 ILCS 5/16-107.6 new)
22    Sec. 16-107.6. Net electricity metering.
23    (a) Beginning January 1, 2018, this Section applies to
24electric utilities serving more than 3,000,000 retail
25customers in the State and the provisions of Section 16-107.5

 

 

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1shall no longer apply to those utilities.
2    (b) The General Assembly finds and declares that a program
3to provide net electricity metering, as defined in this
4Section, for eligible customers can encourage private
5investment in renewable energy resources, stimulate economic
6growth, enhance the continued diversification of Illinois'
7energy resource mix, and protect the Illinois environment.
8    (c) As used in this Section:
9    "Eligible customer" means a retail customer that owns or
10operates a solar, wind, or other eligible renewable electrical
11generating facility with a rated capacity of not more than
122,000 kilowatts that is located on the customer's premises and
13is intended primarily to offset the customer's own electrical
14requirements.
15    "Electricity provider" means an electric utility or
16alternative retail electric supplier.
17    "Eligible renewable electrical generating facility" means
18a generator powered by solar electric energy, wind, dedicated
19crops grown for electricity generation, agricultural residues,
20untreated and unadulterated wood waste, landscape trimmings,
21livestock manure, anaerobic digestion of livestock or food
22processing waste, fuel cells or microturbines powered by
23renewable fuels, or hydroelectric energy.
24    "Net electricity metering" or "net metering" means the
25measurement, during the billing period applicable to an
26eligible customer, of the net amount of electricity supplied by

 

 

09900HB3328ham001- 132 -LRB099 10473 MLM 33016 a

1an electricity provider to the customer's premises or provided
2to the electricity provider by the customer.
3    (d) A net metering facility shall be equipped with metering
4equipment that can measure the flow of electricity in both
5directions at the same rate. The electricity provider may
6arrange for the local electric utility or a meter service
7provider to install and maintain metering equipment capable of
8measuring the flow of electricity both into and out of the
9eligible customer's facility at the same rate and ratio,
10typically through the use of a dual channel meter.
11    (e) An electricity provider shall measure and charge or
12credit for the net electricity supplied to eligible customers
13whose electric delivery service is provided and measured on a
14kilowatt-demand basis and electric supply service is not
15provided based on hourly pricing in the following manner:
16        (1) If the amount of electricity used by the customer
17    during the billing period exceeds the amount of electricity
18    produced by the customer, then the electricity provider
19    shall charge the customer for the net electricity supplied
20    to and used by the customer as provided in subsection (g)
21    of this Section.
22        (2) If the amount of electricity produced by a customer
23    during the billing period exceeds the amount of electricity
24    used by the customer during that billing period, then the
25    electricity provider supplying that customer shall apply a
26    1:1 kilowatt-hour credit that reflects the kilowatt-hour

 

 

09900HB3328ham001- 133 -LRB099 10473 MLM 33016 a

1    based charges in the customer's electric service rate to a
2    subsequent bill for service to the customer for the net
3    electricity supplied to the electricity provider. The
4    electricity provider shall continue to carry over any
5    excess kilowatt-hour credits earned and apply those
6    credits to subsequent billing periods to offset any
7    customer-generator consumption in those billing periods
8    until all credits are used or until the end of the
9    annualized period.
10        (3) At the end of the year or annualized over the
11    period that service is supplied by means of net metering,
12    or in the event that the retail customer terminates service
13    with the electricity provider prior to the end of the year
14    or the annualized period, any remaining credits in the
15    customer's account shall expire.
16    (f) An electricity provider shall measure and charge or
17credit for the net electricity supplied to eligible customers
18whose electric delivery service is provided and measured on a
19kilowatt-demand basis and electric supply service is provided
20based on hourly or time of use pricing in the following manner:
21        (1) If the amount of electricity used by the customer
22    during any hourly or time-of-use period exceeds the amount
23    of electricity produced by the customer, then the
24    electricity provider shall charge the customer for the net
25    electricity supplied to and used by the customer as
26    provided in subsection (g) of this Section.

 

 

09900HB3328ham001- 134 -LRB099 10473 MLM 33016 a

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

 

 

09900HB3328ham001- 135 -LRB099 10473 MLM 33016 a

1charges and all taxes and fees that would otherwise be
2applicable to the net amount of electricity used by the
3customer. Subsections (e) and (f) of this Section shall not be
4construed to prevent an arms-length agreement between an
5electricity provider and an eligible customer that sets forth
6different prices, terms, and conditions for the provision of
7net metering service, including, but not limited to, the
8provision of the appropriate metering equipment for
9non-residential customers.
10    (h) 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 electric utility
16may not condition participation in a net metering program on
17the signing over of a customer's renewable energy credits;
18provided, however, this subsection (h) shall not be construed
19to prevent an arms-length agreement between an electricity
20provider and an eligible customer that sets forth the ownership
21or title of the credits.
22    (i) An electricity provider shall provide net metering to
23eligible customers until the load of its net metering customers
24equals 5% of the total peak demand supplied by that electricity
25provider during the previous year. Electricity providers are
26authorized to offer net metering beyond the 5% level if they so

 

 

09900HB3328ham001- 136 -LRB099 10473 MLM 33016 a

1choose.
2    (j) Each electricity provider shall maintain records and
3report annually to the Commission the total number of net
4metering customers served by the provider, as well as the type,
5capacity, and energy sources of the generating systems used by
6the net metering customers. Nothing in this Section shall limit
7the ability of an electricity provider to request the redaction
8of information deemed by the Commission to be confidential
9business information. Each electricity provider shall notify
10the Commission when the total generating capacity of its net
11metering customers is equal to or in excess of the 5% cap
12specified in subsection (i) of this Section.
13    (k) Notwithstanding the definition of "eligible customer"
14in subsection (c) of this Section, each electricity provider
15shall allow meter aggregation for the purposes of net metering
16on:
17        (1) properties owned or leased by multiple customers
18    that contribute to the operation of an eligible renewable
19    electrical generating facility through an ownership or
20    leasehold interest of at least 2 kilowatts in such
21    facility, such as a community-owned biomass project, a
22    community-owned solar project, or a community methane
23    digester processing livestock waste from multiple sources,
24    provided that the address at which each such customer
25    receives electric service from the electric utility must be
26    located within 5 miles of the location of the facility and

 

 

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1    that the facility is also located within the utility's
2    service territory; and
3        (2) individual units, apartments, or properties
4    located in a single building that are owned or leased by
5    multiple customers and collectively served by a common
6    eligible renewable electrical generating facility, such as
7    an office or apartment building, a shopping center or strip
8    mall served by photovoltaic panels on the roof.
9    The aggregate demand of all meter aggregation pursuant to
10subparagraphs (1) and (2) of this subsection (k) shall be
11subject to, and counted toward, the 5% cap specified in
12subsection (i) of this Section. In addition, the demand of the
13properties, units, or apartments identified in subparagraphs
14(1) and (2) of this subsection (k) whose meters are aggregated
15shall not exceed 2 megawatts in nameplate capacity in total.
16For the purposes of this subsection (k), "meter aggregation"
17means the combination of reading and billing on a pro rata
18basis for the types of eligible customers described in this
19Section.
20    (l) Nothing in this Section shall affect the right of an
21electricity provider to continue to provide, or the right of a
22retail customer to continue to receive service pursuant to a
23contract for electric service between the electricity provider
24and the retail customer in accordance with the prices, terms,
25and conditions provided for in that contract. Either the
26electricity provider or the customer may require compliance

 

 

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1with the prices, terms, and conditions of the contract.
 
2    (220 ILCS 5/16-108.9 new)
3    Sec. 16-108.9. Microgrid pilot.
4    (a) The General Assembly finds that the electric industry
5is undergoing rapid transformation, including fundamental
6changes regarding how electricity is generated, procured, and
7delivered and how customers are choosing to participate in the
8supply and delivery of electricity to and from the electric
9grid. Building upon the State's goals to increase the
10procurement of electricity from renewable energy resources and
11distributed generation, the General Assembly finds that it is
12now necessary to study how the electric grid could be enhanced
13through reliance on the diverse supply options being connected
14to the grid by traditional suppliers and new market
15participants, such as the utility's customers. Specifically,
16the General Assembly finds that these developments present
17unprecedented opportunities to strengthen the resilience and
18security of the electric grid, particularly with respect to the
19grid's support of the State's critical infrastructure
20dedicated to public safety and health purposes. The General
21Assembly therefore finds that it is beneficial to undertake the
22microgrid pilot described in this Section to explore a variety
23of objectives, including, but not limited to, (i) alternatives
24to upgrading the conventional electric grid, (ii) ways to
25improve electric grid resiliency, security, and outage

 

 

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1management for critical facilities and customers and thus
2reduce the frequency, duration, and cost of major outages, and
3(iii) how to improve the safety and security of critical
4electric infrastructure, including cyber security, for the
5benefit of the public.
6    (b) (1) An electric utility serving more than 3,000,000
7retail customers in Illinois that is also a participating
8utility as defined by Section 16-108.5 of this Act may invest
9an estimated $250,000,000 to develop, construct, and install up
10to 6 microgrids in its service territory over a 5-year period
11that commences upon the date of the Commission's approval of
12the plan submitted pursuant to subsection (d) of this Section.
13Notwithstanding such investment amount, a utility that elects
14to undertake the investment described in this subsection (b)
15shall also be authorized to study, operate, and maintain such
16microgrids.
17    For purposes of this Section, "microgrid" means a group of
18interconnected loads and distributed energy resources with
19clearly defined electrical boundaries that acts as a single
20controllable entity with respect to the grid and can connect
21and disconnect from the grid to enable it to operate in both
22grid-connected or island modes.
23    (2) The locations selected to be served by the microgrids
24shall include critical public health and safety facilities and
25critical infrastructure and transportation facilities that
26provide opportunities to study the operation and benefits of

 

 

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1the microgrid. Facilities and locations may include, but are
2not limited to, the following: military; fire fighting; police;
3aviation; medical and health; HazMat; civil defense and public
4safety warning services; communications; radiological,
5chemical, and other special weapons defense; water pumping and
6treatment facilities; and energy delivery. Nothing in this
7Section shall be interpreted to limit the utility's ability to
8coordinate with governmental agencies regarding the selection
9of locations and facilities to be served. Consistent with the
10provisions of this paragraph (2), a utility that elects to
11undertake the investment described in this Section may develop,
12construct, operate, maintain, and study microgrids located at
13or within the following sites in its service territory:
14        (A) the Bronzeville community of Chicago, whose
15    boundaries are approximately Pershing Road, 31st Street,
16    King Drive, and the Dan Ryan Expressway;
17        (B) the Illinois Medical District as defined by Section
18    1 of the Illinois Medical District Act;
19        (C) an airport, as that term is defined by the Illinois
20    Aeronautics Act, that is located in Winnebago County;
21        (D) the Chicago Air Route Traffic Control Center
22    operated by the Federal Aviation Administration and
23    located in the city of Aurora;
24        (E) the DuPage County Courthouse and Administration
25    Building located in the city of Wheaton; and
26        (F) the water pumping and treatment facilities located

 

 

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1    in the city of Chicago Heights.
2    In the event one or more of the sites approved by the
3Commission pursuant to subsection (d) of this Section becomes
4unsuitable or unavailable to accommodate a microgrid project,
5the electric utility shall select an alternative site or sites
6consistent with the provisions of this subparagraph (2). The
7utility shall submit an informational filing to the Commission
8that identifies the alternative site or sites within 90 days
9after such selection.
10    (3) Notwithstanding any law, rule, regulation, or order to
11the contrary, an electric utility that undertakes the
12investment authorized by this subsection (b):
13        (A) shall study electric generating plants and
14    facilities and electric storage plants and facilities as
15    part of a microgrid project, which shall include the
16    construction, installation, leasing, or ownership of at
17    least 3 of the following: (i) solar photovoltaic
18    facilities; (ii) fuel cells; (iii) natural gas generation,
19    including generation that utilizes combined heat and
20    power; (iv) an electricity storage plant and facilities;
21    (v) geothermal technologies; and (vi) wind turbines;
22        (B) shall be permitted to use the plant or facilities
23    described in subparagraph (A) of this paragraph (3) as
24    follows: (i) for distribution system purposes, (ii) as a
25    source of power, energy, and ancillary services for retail
26    customers located within the boundaries of the microgrid

 

 

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1    during interruptions of services on the distribution
2    system serving the microgrid or such customers, provided
3    that the use of the plant and facilities during these
4    periods and the delivery of electric power and energy that
5    they produce shall be considered and treated as a
6    distribution system reliability function and not as a
7    retail sale of power, and (iii) for sales of energy, power,
8    heat, ancillary services, and other related products and
9    services into any available markets, including, but not
10    limited to, wholesale markets, provided that the utility
11    shall not be required to make such sales and, if it elects
12    not to do so, such election and the results thereof shall
13    not be an unreasonable or imprudent decision;
14        (C) may upgrade the delivery facilities in and
15    supporting the microgrid, including, but not limited to,
16    constructing, installing, operating, and maintaining (i)
17    multiple feeders to provide service within and to the
18    microgrid, (ii) distribution automation and other smart
19    grid facilities, which shall be incremental to the
20    investment amounts set forth in Section 16-108.5 of this
21    Act, and (iii) undergrounding distribution facilities
22    within and providing service to the microgrid; and
23        (D) shall not be required to obtain any certificates of
24    public convenience and necessity under Section 8-406 of
25    this Act or any approvals under Sections 9-212, 9-213 or
26    16-111.5 of this Act.

 

 

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1    (c) An electric utility that elects to undertake the
2investment described in subsection (b) of this Section may, at
3its election, recover the costs of such investment through an
4automatic adjustment clause tariff or through a delivery
5services charge. Regardless of which cost recovery mechanism
6the electric utility elects, the utility shall earn a return on
7the balance of the related plant investment as of December 31
8for a given year, less any related accumulated depreciation and
9any related deferred taxes, at an annual rate equal to the
10utility's weighted average cost of capital as approved by the
11Commission in its most recent order applicable to that utility
12under Article IX or Section 16-108.5 of this Act, including a
13revenue conversion factor calculated to recover or refund all
14additional income taxes that may be payable or receivable as a
15result of that return. The weighted average cost of capital
16shall be increased for a period of 5 years following the date
17on which the utility begins recovering costs incurred pursuant
18to this Section, to add 50 basis points to the return on
19equity. The weighted average cost of capital calculated
20pursuant to this subsection (c) shall be updated from time to
21time to reflect the weighted average cost of capital most
22recently approved by the Commission for the utility.
23    In the event the utility elects to file an automatic
24adjustment clause tariff, such tariff may be filed and
25established outside the context of a general rate case filing
26or a filing under subsection (c) or (d) of Section 16-108.5 of

 

 

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1this Act. The Commission shall review and, after notice and
2hearing, by order approve or approve with modification the
3proposed tariff no later than 90 days after the filing of the
4tariff. A utility may reflect the charges recovered through the
5tariff as a separate line item on customers' bills, but shall
6not be required to do so. A tariff approved and placed into
7effect pursuant to this Section shall remain in effect at the
8discretion of the utility, and the utility may withdraw the
9tariff at any time. At such time as the tariff ceases to be in
10effect, the utility shall recover its costs incurred pursuant
11to this Section through a delivery services charge regardless
12of how the assets are categorized or reflected on the utility's
13books and records of account.
14    An electric utility that elects to undertake the investment
15described in subsection (b) of this Section shall also recover
16the costs it incurs to study, operate, and maintain the
17microgrid projects pursuant to this Section, and may, at its
18election, recover such costs through an automatic adjustment
19clause tariff placed into effect pursuant to this Section, if
20applicable, or through its delivery services charges.
21    (d) If an electric utility elects to undertake the
22investment authorized by subsection (b) of this Section, then
23the utility shall submit to the Commission within 120 days
24after the effective date of this amendatory Act of the 99th
25General Assembly the utility's plan for developing,
26constructing, operating, and analyzing microgrids in its

 

 

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1service territory for the 5-year period commencing upon the
2plan's approval. Such plan shall describe:
3        (1) the utility's current projections for scope,
4    microgrid locations and boundaries, schedule,
5    expenditures, and staffing;
6        (2) whether the utility intends to sell into wholesale
7    markets any portion of the power generated pursuant to the
8    plant or facilities described in subparagraph (A) of
9    paragraph (3) of subsection (b) of this Section and, if so,
10    how such sales will be executed and revenues applied to
11    offset the costs of the microgrid pilot; and
12        (3) the criteria, including specific performance
13    metrics, for evaluating the extent to which the microgrids
14    developed under this Section achieved the objectives set
15    out in subsection (a) of this Section.
16    Within 90 days after the utility files its plan pursuant to
17this subsection (d), the Commission shall review and, after
18notice and hearing, enter an order approving the plan if it
19finds that the plan conforms to the requirements of this
20Section or, if the Commission finds that the plan does not
21conform to the requirements of this Section, the Commission
22must enter an order describing in detail the reasons for not
23approving the plan. The utility may resubmit its plan to
24address the Commission's concerns, and the Commission shall
25expeditiously review and by order approve the revised plan if
26it finds that the plan conforms to the requirements of this

 

 

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1Section, provided that such order shall be entered no later
2than 90 days after the utility resubmits its plan.
3    No later than 90 days after the close of each plan year,
4the utility shall submit a report to the Commission that
5includes any updates to the plan, a schedule for the next plan
6year, the expenditures made for the prior plan year and
7cumulatively, an evaluation of the extent to which the
8objectives of this microgrid pilot are being achieved, and the
9number of full-time equivalent jobs created for the prior plan
10year and cumulatively. Within 60 days after the utility files
11its annual report, the Commission may enter into an
12investigation of the report. If the Commission commences an
13investigation, it must, after notice and hearing, enter an
14order approving the report or approving the report with
15modification necessary to bring it into compliance with this
16Section no later than 180 days after the utility files such
17report. If the Commission does not initiate an investigation
18within 60 days after the utility files its annual report, then
19the filing shall be deemed accepted by the Commission.
20    The utility may continue operating, maintaining, and
21studying the microgrids developed and constructed pursuant to
22this Section following the end of the 5-year plan period, and
23the costs incurred by the utility regarding such continued
24operation and maintenance and to comply with the requirements
25of this Section shall continue to be recoverable following the
26end of the 5-year plan period. However, any generating or

 

 

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1storage facility that becomes inoperable after the initial
25-year period may not be replaced without the approval of the
3Commission unless the facility will be used solely for the
4purposes described in subparagraph (B) of paragraph (3) of
5subsection (b) of this Section.
6    To the extent feasible and consistent with State and
7federal law, the investments made pursuant to this Section
8should provide employment opportunities for all segments of the
9population and workforce, including minority-owned and
10female-owned business enterprises, and shall not, consistent
11with State and federal law, discriminate based on race or
12socioeconomic status.
13    (e) No later than 365 days following the end of the 5-year
14plan period, the electric utility shall submit its final report
15to the Commission evaluating the extent to which the objectives
16of this microgrid pilot have been achieved, reporting on its
17performance under the metrics established in the plan, and
18proposing any additional study or action required to continue
19the further development of microgrids in the electric utility's
20service territory. In addition, the electric utility shall
21demonstrate that it created an average of 50 full-time
22equivalent jobs in Illinois, per microgrid project, during the
23construction and operation of the microgrids. The jobs shall
24include direct jobs, contractor positions, and induced jobs. If
25the Commission enters an order finding, after notice and
26hearing, that the utility did not satisfy its job commitment

 

 

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1described in this subsection (e) for reasons that are
2reasonably within its control, then the Commission shall also
3determine, after consideration of the evidence, including, but
4not limited to, evidence submitted by the Department of
5Commerce and Economic Opportunity and the utility, the
6deficiency in the number of full-time equivalent jobs due to
7such failure. The Commission shall notify the Department of any
8proceeding that is initiated pursuant to this subsection (e).
9For each full-time equivalent job deficiency that the
10Commission finds as set forth in this subsection (e), the
11utility shall, within 30 days after the entry of the
12Commission's order, pay $6,000 to a fund for training grants
13administered under Section 605-800 of the Department of
14Commerce and Economic Opportunity Law, which shall not be a
15recoverable expense.
16    No later than 365 days following the date on which the
17utility submits its final report pursuant to this subsection
18(e), the Commission shall submit a report to the General
19Assembly evaluating the extent to which the objectives of the
20microgrid pilot have been achieved, reporting on the utility's
21performance under the metrics established in its plan, and
22proposing any additional study or action required to continue
23the further development of microgrids in the utility's service
24territory.
25    (f) In no event, absent General Assembly approval, shall
26the capital investment costs incurred by an electric utility

 

 

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1pursuant to this Section exceed $300,000,000. If the utility's
2updated cost estimates for implementing its plan exceed the
3limitation imposed by this subsection (f), then it shall submit
4a report to the Commission that identifies the increased costs
5and explains the reason or reasons for the increased costs no
6later than the year in which the utility estimates it will
7exceed the limitation. The Commission shall review the report
8and shall, within 90 days after the utility files the report,
9report to the General Assembly its findings regarding the
10utility's report. If the General Assembly does not amend the
11limitation imposed by this subsection (f), then the utility may
12modify its plan so as not to exceed the limitation imposed by
13this subsection (f) and may propose corresponding changes in
14its plan, and the Commission may modify the metrics established
15pursuant to this Section accordingly.
16    (g) All facilities and equipment installed pursuant to this
17Section shall be considered and treated as distribution system
18facilities.
 
19    (220 ILCS 5/16-108.10 new)
20    Sec. 16-108.10. Electric vehicle charging station pilot.
21    (a) The General Assembly finds that substantial
22opportunities exist to expand the purchase and use of electric
23vehicles in Illinois and thereby reduce the State's reliance on
24conventional vehicles that use petroleum as their sole source
25of fuel. The General Assembly further finds that increased

 

 

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1usage of electric vehicles in Illinois will improve the State's
2air quality by reducing greenhouse gas emissions and other
3environmental pollutants. These benefits will be realized by
4all citizens of the State, including low-income households.
5While the General Assembly has previously enacted legislation
6to address the installation of electric vehicle charging
7stations, the General Assembly finds that electric vehicles are
8substantially underutilized in Illinois, and the market
9remains nascent. The General Assembly further finds that the
10insufficient number of electric vehicle charging stations in
11the State has contributed to Illinoisans' reluctance to
12purchase electric vehicles. The General Assembly therefore
13finds that it is now necessary for electric utilities to
14undertake substantial investment in the development,
15construction, and installation of electric vehicle charging
16stations as described in this Section.
17    (b)(1) An electric utility that serves more than 3,000,000
18retail customers in the State may invest a maximum of
19$100,000,000 to develop, construct, and install up to 5,000
20publicly-accessible electric vehicle charging stations in its
21service territory over a 5-year period that commences upon the
22date of the Commission's approval of the plan submitted
23pursuant to subsection (d) of this Section. Notwithstanding
24such maximum investment amount, a utility that elects to
25undertake the investment described in this subsection (b) shall
26also be authorized to operate and maintain such stations. For

 

 

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1purposes of this Section, "electric vehicle charging station"
2shall have the meaning set forth in Section 16-128A of this
3Act.
4    (2) The deployment of electric vehicle charging stations
5shall be focused primarily on the following priority areas:
6        (A) publicly accessible parking areas, including
7    rights-of-way and parking facilities, to support residents
8    of multi-unit dwelling buildings with respect to such use;
9        (B) workplace locations accessible to employees and
10    visitors, provided that electric vehicle charging stations
11    designated for use by an employer's fleet of vehicles shall
12    not be installed pursuant to this Section unless the
13    charging station is used by both the employer's fleet and
14    the public;
15        (C) municipal parking lots;
16        (D) other locations designated for long-term or
17    overnight public parking; and
18        (E) economically disadvantaged locations.
19    (3) Notwithstanding any law, rule, regulation, or order to
20the contrary:
21        (A) users of electric vehicle charging stations
22    deployed by an electric utility pursuant to this Section
23    shall be deemed to be retail customers of the electric
24    utility as defined by Section 16-102 of this Act;
25        (B) electric utilities may market, advertise, and
26    promote the use of the electric vehicle charging stations

 

 

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1    installed pursuant to this Section, including, but not
2    limited to, the sale of electric power and energy from such
3    stations;
4        (C) electric utilities may construct, install, own,
5    operate, and maintain solar photovoltaic generating
6    stations to supply the electric vehicle charging station
7    facilities deployed pursuant to this Section and to use the
8    energy output of such generating stations to serve the
9    needs of the electric vehicle charging station facilities;
10    the costs of constructing and installing such facilities
11    shall be included within and subject to the maximum
12    investment amount set forth in paragraph (1) of this
13    subsection (b);
14        (D) the power, energy, and ancillary services required
15    to serve the needs of the electric vehicle charging
16    stations shall be included in the electric utility's load
17    forecasts for its eligible retail customers submitted
18    pursuant to Section 16-111.5 of this Act; however, the
19    costs of the power, energy, and ancillary services shall
20    not be recovered pursuant to that Section, and the utility
21    shall instead recover such costs pursuant to this Section
22    as specified in the plan submitted pursuant to subsection
23    (d) of this Section; and
24        (E) electric utilities that construct, operate, and
25    maintain facilities described in this subsection (b) shall
26    not be required to obtain any certificates of public

 

 

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1    convenience and necessity under Section 8-406 of this Act
2    or any approvals under Sections 9-212, 9-213, or 16-111.5
3    of this Act and shall not be subject to the certification
4    requirements set forth in Section 16-128A of this Act.
5    (c) An electric utility that elects to undertake the
6investment in electric vehicle charging station facilities
7described in subsection (b) of this Section may, at its
8election, recover the costs of such investment through an
9automatic adjustment clause tariff or through a delivery
10services charge, provided that the cost recovery of such
11investment shall not include the energy charges associated with
12the electric vehicle charging stations, which shall be
13separately recovered as an operating expense as described in
14the plan submitted pursuant to subsection (d) of this Section.
15Regardless of which cost recovery mechanism the electric
16utility elects, the utility shall earn a return on the balance
17of the related plant investment as of December 31 for a given
18year, less any related accumulated depreciation and any related
19deferred taxes, at an annual rate equal to the utility's
20weighted average cost of capital as approved by the Commission
21in its most recent order applicable to that utility under
22Article IX or Section 16-108.5 of this Act, including a revenue
23conversion factor calculated to recover or refund all
24additional income taxes that may be payable or receivable as a
25result of that return. The weighted average cost of capital
26shall be increased for a period of 5 years following the date

 

 

09900HB3328ham001- 154 -LRB099 10473 MLM 33016 a

1on which the utility begins recovering costs incurred pursuant
2to this Section, to add 50 basis points to the return on
3equity. The weighted average cost of capital calculated
4pursuant to this subsection (c) shall be updated from time to
5time to reflect the weighted average cost of capital most
6recently approved by the Commission for the utility.
7    If the utility elects to file an automatic adjustment
8clause tariff, the tariff may be filed and established outside
9the context of a general rate case filing or a filing under
10subsection (c) or (d) of Section 16-108.5 of this Act and shall
11be filed no later than 120 days after the effective date of
12this amendatory Act of the 99th General Assembly. The
13Commission shall review and, after notice and hearing, by order
14approve or approve with modification the proposed tariff no
15later than 180 days after the filing of the tariff. A tariff
16approved and placed into effect pursuant to this Section shall
17remain in effect at the discretion of the utility, and the
18utility may withdraw the tariff at any time. At such time as
19the tariff ceases to be in effect, the utility shall recover
20its costs incurred pursuant to this Section through a delivery
21services charge regardless of how the assets are categorized or
22reflected on the utility's books and records of account.
23    An electric utility that elects to undertake the investment
24in electric vehicle charging station facilities described in
25subsection (b) of this Section shall also recover the costs it
26incurs to operate and maintain such facilities installed

 

 

09900HB3328ham001- 155 -LRB099 10473 MLM 33016 a

1pursuant to this Section and may, at its election, recover
2those costs through an automatic adjustment clause tariff
3placed into effect pursuant to this Section, if applicable, or
4through its delivery services charges.
5    (d) If an electric utility elects to undertake the
6investment authorized by subsection (b) of this Section, then
7the utility shall submit its plan to the Commission within 120
8days after the effective date of this amendatory Act of the
999th General Assembly. The utility shall consult with the
10Illinois Electric Vehicle Advisory Council and Chicago Area
11Clean Cities Coalition prior to filing the plan. Such plan must
12include (i) the criteria and a description of the process for
13selecting the sites described in paragraph (2) of subsection
14(b) of this Section, (ii) a description of the process by which
15sites that fall within paragraph (2) of subsection (b) of this
16Section may submit applications for installation of an electric
17vehicle charging station at a particular location, (iii) a
18description of the pricing proposals the utility intends to
19pilot during the plan's 5-year period to recover the costs of
20the energy used at the electric vehicle charging stations,
21including, but not limited, to demand-response pricing, and
22(iv) a preliminary list of the recommended locations of the
23electric vehicle charging stations planned to be installed
24during the first annual period of investment under this
25Section, which shall commence upon the date of the Commission's
26approval of the plan.

 

 

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1    Within 90 days after the utility files its plan pursuant to
2this subsection (d), the Commission shall review and, after
3notice and hearing, enter an order approving the plan if it
4finds that the plan conforms to the requirements of this
5Section or, if the Commission finds that the plan does not
6conform to the requirements of this Section, the Commission
7shall enter an order describing in detail the reasons for not
8approving the plan. The utility may resubmit its plan to
9address the Commission's concerns, and the Commission shall
10expeditiously review and by order approve the revised plan if
11it finds that the plan conforms to the requirements of this
12Section, provided that such order shall be entered no later
13than 90 days after the utility resubmits its plan. No later
14than 90 days after the close of each plan year, the utility
15shall submit a report to the Commission that includes any
16updates to the plan, a schedule for the next plan year, the
17expenditures made for the prior plan year and cumulatively, and
18the number of full-time equivalent jobs created for the prior
19plan year and cumulatively.
20    The utility may continue operating and maintaining the
21electric vehicle charging stations deployed pursuant to this
22Section following the end of the 5-year plan period, and the
23costs incurred by the utility regarding such continued
24operation and maintenance and to comply with the requirements
25of this Section shall continue to be recoverable following the
26end of the 5-year plan period. If the utility finds that the

 

 

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1market for electric vehicles remains nascent following the
2first 2 years of deployment under the plan, then the utility
3may file a petition with the Commission requesting approval to
4terminate the pilot program described in, and plan approved
5pursuant to, this Section. If the Commission approves such
6termination and the utility is recovering its costs incurred
7pursuant to this Section through an automatic adjustment clause
8tariff authorized by subsection (c) of this Section, then the
9utility shall begin recovering such costs through its delivery
10services charges established in the next general rate case
11under Section 9-201 of this Act or in the next formula rate
12update proceeding under subsection (d) of Section 16-108.5 of
13this Act, as applicable. At such time as the utility begins
14recovering its costs incurred under this Section through
15delivery services charges, the automatic adjustment clause
16tariff shall terminate.
17    To the extent feasible and consistent with State and
18federal law, the investments made pursuant to this Section
19should provide employment opportunities for all segments of the
20population and workforce, including minority-owned and
21female-owned business enterprises, and shall not, consistent
22with State and federal law, discriminate based on race or
23socioeconomic status.
24    (e) No later than 365 days following the end of the 5-year
25plan period, the electric utility shall submit its final report
26to the Commission evaluating the development, construction,

 

 

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1installation, operation, and maintenance of electric vehicle
2charging stations and solar photovoltaic generating stations
3and the extent to which the objectives stated in subsection (a)
4of this Section have been achieved. In addition, during the
55-year plan period, the electric utility shall create 50
6full-time equivalent jobs in Illinois through the development,
7construction, installation, operation, and maintenance of
8electric vehicle charging stations and solar photovoltaic
9generating stations. The jobs shall include direct jobs,
10contractor positions, and induced jobs. If the Commission
11enters an order finding, after notice and hearing, that the
12utility did not satisfy its job commitment described in this
13subsection (e) for reasons that are reasonably within its
14control, then the Commission shall also determine, after
15consideration of the evidence, including, but not limited to,
16evidence submitted by the Department of Commerce and Economic
17Opportunity and the utility, the deficiency in the number of
18full-time equivalent jobs due to such failure. The Commission
19shall notify the Department of any proceeding that is initiated
20pursuant to this subsection (e). For each full-time equivalent
21job deficiency that the Commission finds as set forth in this
22subsection (e), the utility shall, within 30 days after the
23entry of the Commission's order, pay $6,000 to a fund for
24training grants administered under Section 605-800 of the
25Department of Commerce and Economic Opportunity Law, which
26shall not be a recoverable expense.

 

 

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1    (f) All facilities and equipment installed pursuant to this
2Section shall be considered and treated as distribution system
3facilities.
 
4    (220 ILCS 5/16-108.11 new)
5    Sec. 16-108.11. Voltage optimization implementation.
6    (a) The General Assembly finds that electric utilities'
7energy efficiency and demand-response plans approved pursuant
8to Section 8-103 of this Act have already implemented many of
9the lowest-cost energy efficiency measures available in the
10market, and further finds that it is necessary to continue to
11research and identify new energy efficiency measures that are
12cost effective. The General Assembly finds that voltage
13optimization is an energy efficiency measure that can deliver
14cost-effective energy savings for all retail customers,
15including low-income customers. For purposes of this Section,
16"cost-effective" shall have the meaning set forth in Section
178-103 of this Act.
18    (b) A participating utility may file a plan with the
19Commission to begin implementing cost-effective voltage
20optimization on identified elements of its electric delivery
21system. The plan shall be submitted with a recent voltage
22optimization study identifying suitable facilities and
23potential benefits and costs of voltage optimization. The plan
24shall cover a period that does not extend beyond December 31,
252017, and its scope shall be limited to achieving no more than

 

 

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1the unmet portion of the utility's statutory energy savings
2goals calculated pursuant to subsections (b) and (i) of Section
38-103 of this Act for the multi-year planning period ending on
4December 31, 2017. For purposes of this Section, such "unmet
5portion c" shall be calculated as the difference between the
6following:
7        (1) the utility's statutory energy savings goals
8    calculated pursuant to subsections (b) and (i) of Section
9    8-103 of this Act for the multi-year planning period ending
10    on December 31, 2017; and
11        (2) the amount of energy savings projected to be
12    achieved during the multi-year planning period ending on
13    December 31, 2017, which shall be determined using the
14    energy efficiency energy savings goals set forth in the
15    utility's most recent 3-year energy efficiency and
16    demand-response plan approved by the Commission, as
17    modified by subsection (i) of Section 8-103 of this Act,
18    and the energy savings projected to be achieved through the
19    energy efficiency measures to be implemented during the
20    period June 1, 2014 through December 31, 2017 as approved
21    by the Commission pursuant to Section 16-111.5B of this
22    Act.
23    The Commission shall review the plan to determine if it is
24consistent with the scope and calculations set forth in this
25subsection (b) and that it is cost effective. The Commission
26shall, after notice and hearing, by order approve such plan if

 

 

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1it is consistent with this subsection (b) and cost effective or
2approve it with modifications required to meet those
3requirements. Notwithstanding the limitations set forth in
4subsection (d) of Section 8-103 of this Act, the utility shall
5recover all of its costs incurred pursuant to a plan approved
6under this Section through the provisions of Article IX or
7Section 16-108.5 of this Act. Nothing in this Section is
8intended to prohibit or limit a utility from beginning to
9validate voltage optimization prior to the approval of its plan
10under this Section, and the costs of such validating shall be
11recovered through the provisions of Article IX or Section
1216-108.5 of this Act.
13    (c) An electric utility that is implementing
14cost-effective voltage optimization pursuant to a plan
15approved by the Commission pursuant to this Section shall
16create 50 full-time equivalent jobs in Illinois related to such
17implementation during the plan period. The jobs shall include
18direct jobs, contractor positions, and induced jobs. If the
19Commission enters an order finding, after notice and hearing,
20that the utility did not satisfy its job commitment described
21in this subsection (c) for reasons that are reasonably within
22its control, then the Commission shall also determine, after
23consideration of the evidence, including, but not limited to,
24evidence submitted by the Department of Commerce and Economic
25Opportunity and the utility, the deficiency in the number of
26full-time equivalent jobs due to such failure. The Commission

 

 

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1shall notify the Department of any proceeding that is initiated
2pursuant to this subsection (c). For each full-time equivalent
3job deficiency that the Commission finds as set forth in this
4subsection (c), the utility shall, within 30 days after the
5entry of the Commission's order, pay $6,000 to a fund for
6training grants administered under Section 605-800 of the
7Department of Commerce and Economic Opportunity Law, which
8shall not be a recoverable expense.
9    To the extent feasible and consistent with State and
10federal law, the investments made pursuant to this Section
11should provide employment opportunities for all segments of the
12population and workforce, including minority-owned and
13female-owned business enterprises, and shall not, consistent
14with State and federal law, discriminate based on race or
15socioeconomic status.
16    (d) A utility that is implementing voltage optimization
17pursuant to this Section shall address the continued
18implementation of voltage optimization in the assessment
19submitted pursuant to paragraph (8) of subsection (g) of
20Section 8-103 of this Act for its proposed energy efficiency
21plan filed on or before March 1, 2017 for the multi-year
22planning period commencing on January 1, 2018.
 
23    (220 ILCS 5/16-108.12 new)
24    Sec. 16-108.12. Energy low-income and support program.
25    (a) Beginning on January 1, 2017, without obtaining any

 

 

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1approvals from the Commission or any other agency, regardless
2of whether any such approval would otherwise be required, a
3participating utility that is not a combination utility, as
4defined by Section 16-108.5 of this Act, shall contribute
5$10,000,000 per year for 5 years to the energy low-income and
6support program, which is intended to fund customer assistance
7programs with the primary purpose being avoidance of imminent
8disconnection. Such programs may include:
9        (1) a residential hardship program that may partner
10    with community-based organizations, including senior
11    citizen organizations, and provides grants to low-income
12    residential customers, including low-income senior
13    citizens, who demonstrate a hardship;
14        (2) a program that provides grants and other bill
15    payment concessions to disabled veterans who demonstrate a
16    hardship and members of the armed services or reserve
17    forces of the United States or members of the Illinois
18    National Guard who are on active duty pursuant to an
19    executive order of the President of the United States, an
20    act of the Congress of the United States, or an order of
21    the Governor and who demonstrate a hardship;
22        (3) a budget assistance program that provides tools and
23    education to low-income senior citizens to assist them with
24    obtaining information regarding energy usage and effective
25    means of managing energy costs;
26        (4) a non-residential special hardship program that

 

 

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1    provides grants to non-residential customers, such as
2    small businesses and non-profit organizations, that
3    demonstrate a hardship, including those providing services
4    to senior citizen and low-income customers; and
5        (5) a performance-based assistance program that
6    provides grants to encourage residential customers to make
7    on-time payments by matching a portion of the customer's
8    payments or providing credits towards arrearages.
9    The payments made by a participating utility pursuant to
10this Section shall not be a recoverable expense. A
11participating utility may elect to fund either new or existing
12customer assistance programs, including, but not limited to,
13those that are administered by the utility.
14    Programs that use funds that are provided by an electric
15utility to reduce utility bills may be implemented through
16tariffs that are filed with and reviewed by the Commission. If
17a utility elects to file tariffs with the Commission to
18implement all or a portion of the programs, those tariffs
19shall, regardless of the date actually filed, be deemed
20accepted and approved, and shall become effective on the date
21that they are filed. The electric utilities whose customers
22benefit from the funds that are disbursed as contemplated in
23this Section shall file annual reports documenting the
24disbursement of those funds with the Commission. The Commission
25may audit disbursement of the funds to ensure they were
26disbursed consistently with this Section.

 

 

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1    If the Commission finds that a participating utility is no
2longer eligible to update the performance-based formula rate
3tariff pursuant to subsection (d) of Section 16-108.5 of this
4Act or the performance-based formula rate is otherwise
5terminated, then the participating utility's obligations under
6this Section shall immediately terminate.
 
7    (220 ILCS 5/16-111.5)
8    Sec. 16-111.5. Provisions relating to procurement.
9    (a) An electric utility that on December 31, 2005 served at
10least 100,000 customers in Illinois shall procure power and
11energy for its eligible retail customers in accordance with the
12applicable provisions set forth in Section 1-75 of the Illinois
13Power Agency Act and this Section. A small multi-jurisdictional
14electric utility that on December 31, 2005 served less than
15100,000 customers in Illinois may elect to procure power and
16energy for all or a portion of its eligible Illinois retail
17customers in accordance with the applicable provisions set
18forth in this Section and Section 1-75 of the Illinois Power
19Agency Act. This Section shall not apply to a small
20multi-jurisdictional utility until such time as a small
21multi-jurisdictional utility requests the Illinois Power
22Agency to prepare a procurement plan for its eligible retail
23customers. "Eligible retail customers" for the purposes of this
24Section means those retail customers that purchase power and
25energy from the electric utility under fixed-price bundled

 

 

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1service tariffs, other than those retail customers whose
2service is declared or deemed competitive under Section 16-113
3and those other customer groups specified in this Section,
4including self-generating customers, customers electing hourly
5pricing, or those customers who are otherwise ineligible for
6fixed-price bundled tariff service. Those customers that are
7excluded from the definition of "eligible retail customers"
8shall not be included in the procurement plan load
9requirements, and the utility shall procure any supply
10requirements, including capacity, ancillary services, and
11hourly priced energy, in the applicable markets as needed to
12serve those customers, provided that the utility may include in
13its procurement plan load requirements for the load that is
14associated with those retail customers whose service has been
15declared or deemed competitive pursuant to Section 16-113 of
16this Act to the extent that those customers are purchasing
17power and energy during one of the transition periods
18identified in subsection (b) of Section 16-113 of this Act.
19    (b) A procurement plan shall be prepared for each electric
20utility consistent with the applicable requirements of the
21Illinois Power Agency Act and this Section. For purposes of
22this Section, Illinois electric utilities that are affiliated
23by virtue of a common parent company are considered to be a
24single electric utility. Small multi-jurisdictional utilities
25may request a procurement plan for a portion of or all of its
26Illinois load. Each procurement plan shall analyze the

 

 

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1projected balance of supply and demand for eligible retail
2customers over a 5-year period with the first planning year
3beginning on June 1 of the year following the year in which the
4plan is filed. The plan shall specifically identify the
5wholesale products to be procured following plan approval, and
6shall follow all the requirements set forth in the Public
7Utilities Act and all applicable State and federal laws,
8statutes, rules, or regulations, as well as Commission orders.
9Nothing in this Section precludes consideration of contracts
10longer than 5 years and related forecast data. Unless specified
11otherwise in this Section, in the procurement plan or in the
12implementing tariff, any procurement occurring in accordance
13with this plan shall be competitively bid through a request for
14proposals process. Approval and implementation of the
15procurement plan shall be subject to review and approval by the
16Commission according to the provisions set forth in this
17Section. A procurement plan shall include each of the following
18components:
19        (1) Hourly load analysis. This analysis shall include:
20            (i) multi-year historical analysis of hourly
21        loads;
22            (ii) switching trends and competitive retail
23        market analysis;
24            (iii) known or projected changes to future loads;
25        and
26            (iv) growth forecasts by customer class.

 

 

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

 

 

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

 

 

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1        combination, to meet that portion of its load
2        requirements not met through pre-existing contracts,
3        including but not limited to monthly 5 x 16 peak period
4        block energy, monthly off-peak wrap energy, monthly 7 x
5        24 energy, annual 5 x 16 energy, annual off-peak wrap
6        energy, annual 7 x 24 energy, monthly capacity, annual
7        capacity, peak load capacity obligations, capacity
8        purchase plan, and ancillary services;
9            (v) proposed term structures for each wholesale
10        product type included in the proposed procurement plan
11        portfolio of products; and
12            (vi) an assessment of the price risk, load
13        uncertainty, and other factors that are associated
14        with the proposed procurement plan; this assessment,
15        to the extent possible, shall include an analysis of
16        the following factors: contract terms, time frames for
17        securing products or services, fuel costs, weather
18        patterns, transmission costs, market conditions, and
19        the governmental regulatory environment; the proposed
20        procurement plan shall also identify alternatives for
21        those portfolio measures that are identified as having
22        significant price risk.
23        (4) Proposed procedures for balancing loads. The
24    procurement plan shall include, for load requirements
25    included in the procurement plan, the process for (i)
26    hourly balancing of supply and demand and (ii) the criteria

 

 

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1    for portfolio re-balancing in the event of significant
2    shifts in load.
3        (5) Renewable energy resources plan. The procurement
4    plan shall include a renewable energy resources plan that
5    shall ensure adequate, reliable, affordable, efficient,
6    and environmentally sustainable renewable energy resources
7    at the lowest total cost over time, taking into account any
8    benefits of price stability. The renewable energy
9    resources plan shall include:
10            (i) a description of the renewable energy
11        resources, including renewable energy credits proposed
12        to be procured pursuant to Section 1-56 and subsection
13        (c) of Section 1-75 of the Illinois Power Agency Act;
14            (ii) a planning horizon and a comparison of the
15        projected costs and benefits of procuring renewable
16        resources for various contract terms based on market
17        evidence;
18            (iii) an analysis of the possible impacts of
19        customer migration between alternative retail electric
20        suppliers and electric utility supply service and a
21        description of how the plan has been designed to limit
22        the potential that eligible retail customers may pay
23        for curtailed credits in excess of those required to
24        meet the minimum for attainment of the goals set forth
25        in paragraph (1) of subsection (c) of Section 1-75 of
26        this Act;

 

 

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1            (iv) an assignment to a particular utility's
2        service territory of the renewable energy credits
3        proposed to be procured for purposes of addressing
4        customer migration in accordance with paragraph (1) of
5        subsection (c) of Section 1-75 of the Illinois Power
6        Agency Act, taking into account the renewable goals of
7        the Illinois Power Agency; and
8            (v) an explanation of how the Illinois Power Agency
9        plans to utilize available funds for its planned
10        renewable energy procurement, identifying specifically
11        the source of funds to be used, including the Illinois
12        Power Agency Renewable Energy Resources Fund, moneys
13        accumulated by the electric utility in respect of
14        service to customers under hourly pricing tariffs
15        pursuant to paragraph (5) of subsection (c) of Section
16        1-75 of the Illinois Power Agency Act, and any other
17        moneys to be collected by the electric utility for
18        procurements conducted pursuant to paragraph (1) of
19        subsection (c) of Section 1-75 of the Illinois Power
20        Agency Act.
21        Planning of the procurement of renewable energy
22    credits through long-term contracts by the Illinois Power
23    Agency under subsection (c) of Section 1-56 of the Illinois
24    Power Agency Act shall recognize the possible impacts of
25    customer migration between alternative retail electric
26    suppliers and electric utility electric supply service and

 

 

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1    shall be designed to limit the potential that eligible
2    retail customers may be required to pay for curtailed
3    credits in excess of the amounts required to meet the
4    minimum for attainment of the goals set forth in paragraph
5    (1) of subsection (c) of Section 1-75 of the Illinois Power
6    Agency Act.
7    (c) The procurement process set forth in Section 1-75 of
8the Illinois Power Agency Act and subsection (e) of this
9Section shall be administered by a procurement administrator
10and monitored by a procurement monitor.
11        (1) The procurement administrator shall:
12            (i) design the final procurement process in
13        accordance with Section 1-75 of the Illinois Power
14        Agency Act and subsection (e) of this Section following
15        Commission approval of the procurement plan;
16            (ii) develop benchmarks in accordance with
17        subsection (e)(3) to be used to evaluate bids; these
18        benchmarks shall be submitted to the Commission for
19        review and approval on a confidential basis prior to
20        the procurement event;
21            (iii) serve as the interface between the electric
22        utility and suppliers;
23            (iv) manage the bidder pre-qualification and
24        registration process;
25            (v) obtain the electric utilities' agreement to
26        the final form of all supply contracts and credit

 

 

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1        collateral agreements;
2            (vi) administer the request for proposals process;
3            (vii) have the discretion to negotiate to
4        determine whether bidders are willing to lower the
5        price of bids that meet the benchmarks approved by the
6        Commission; any post-bid negotiations with bidders
7        shall be limited to price only and shall be completed
8        within 24 hours after opening the sealed bids and shall
9        be conducted in a fair and unbiased manner; in
10        conducting the negotiations, there shall be no
11        disclosure of any information derived from proposals
12        submitted by competing bidders; if information is
13        disclosed to any bidder, it shall be provided to all
14        competing bidders;
15            (viii) maintain confidentiality of supplier and
16        bidding information in a manner consistent with all
17        applicable laws, rules, regulations, and tariffs;
18            (ix) submit a confidential report to the
19        Commission recommending acceptance or rejection of
20        bids;
21            (x) notify the utility of contract counterparties
22        and contract specifics; and
23            (xi) administer related contingency procurement
24        events.
25        (2) The procurement monitor, who shall be retained by
26    the Commission, shall:

 

 

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1            (i) monitor interactions among the procurement
2        administrator, suppliers, and utility;
3            (ii) monitor and report to the Commission on the
4        progress of the procurement process;
5            (iii) provide an independent confidential report
6        to the Commission regarding the results of the
7        procurement event;
8            (iv) assess compliance with the procurement plans
9        approved by the Commission for each utility that on
10        December 31, 2005 provided electric service to a least
11        100,000 customers in Illinois and for each small
12        multi-jurisdictional utility that on December 31, 2005
13        served less than 100,000 customers in Illinois;
14            (v) preserve the confidentiality of supplier and
15        bidding information in a manner consistent with all
16        applicable laws, rules, regulations, and tariffs;
17            (vi) provide expert advice to the Commission and
18        consult with the procurement administrator regarding
19        issues related to procurement process design, rules,
20        protocols, and policy-related matters; and
21            (vii) consult with the procurement administrator
22        regarding the development and use of benchmark
23        criteria, standard form contracts, credit policies,
24        and bid documents.
25    (d) Except as provided in subsection (j), the planning
26process shall be conducted as follows:

 

 

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1        (1) Beginning in 2008, each Illinois utility procuring
2    power pursuant to this Section shall annually provide a
3    range of load forecasts to the Illinois Power Agency by
4    July 15 of each year, or such other date as may be required
5    by the Commission or Agency. The load forecasts shall cover
6    the 5-year procurement planning period for the next
7    procurement plan and shall include hourly data
8    representing a high-load, low-load and expected-load
9    scenario for the load of the eligible retail customers. The
10    utility shall provide supporting data and assumptions for
11    each of the scenarios.
12        (2) Beginning in 2008, the Illinois Power Agency shall
13    prepare a procurement plan by August 15th of each year, or
14    such other date as may be required by the Commission. The
15    procurement plan shall identify the portfolio of
16    demand-response and power and energy products to be
17    procured. Cost-effective demand-response measures shall be
18    procured as set forth in item (iii) of subsection (b) of
19    this Section. Copies of the procurement plan shall be
20    posted and made publicly available on the Agency's and
21    Commission's websites, and copies shall also be provided to
22    each affected electric utility. An affected utility shall
23    have 30 days following the date of posting to provide
24    comment to the Agency on the procurement plan. Other
25    interested entities also may comment on the procurement
26    plan. All comments submitted to the Agency shall be

 

 

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1    specific, supported by data or other detailed analyses,
2    and, if objecting to all or a portion of the procurement
3    plan, accompanied by specific alternative wording or
4    proposals. All comments shall be posted on the Agency's and
5    Commission's websites. During this 30-day comment period,
6    the Agency shall hold at least one public hearing within
7    each utility's service area for the purpose of receiving
8    public comment on the procurement plan. Within 14 days
9    following the end of the 30-day review period, the Agency
10    shall revise the procurement plan as necessary based on the
11    comments received and file the procurement plan with the
12    Commission and post the procurement plan on the websites.
13        (3) Within 5 days after the filing of the procurement
14    plan, any person objecting to the procurement plan shall
15    file an objection with the Commission. Within 10 days after
16    the filing, the Commission shall determine whether a
17    hearing is necessary. The Commission shall enter its order
18    confirming or modifying the procurement plan within 90 days
19    after the filing of the procurement plan by the Illinois
20    Power Agency.
21        (4) The Commission shall approve the procurement plan,
22    including expressly the forecast used in the procurement
23    plan, if the Commission determines that it will ensure
24    adequate, reliable, affordable, efficient, and
25    environmentally sustainable electric service at the lowest
26    total cost over time, taking into account any benefits of

 

 

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1    price stability.
2    (e) The procurement process shall include each of the
3following components:
4        (1) Solicitation, pre-qualification, and registration
5    of bidders. The procurement administrator shall
6    disseminate information to potential bidders to promote a
7    procurement event, notify potential bidders that the
8    procurement administrator may enter into a post-bid price
9    negotiation with bidders that meet the applicable
10    benchmarks, provide supply requirements, and otherwise
11    explain the competitive procurement process. In addition
12    to such other publication as the procurement administrator
13    determines is appropriate, this information shall be
14    posted on the Illinois Power Agency's and the Commission's
15    websites. The procurement administrator shall also
16    administer the prequalification process, including
17    evaluation of credit worthiness, compliance with
18    procurement rules, and agreement to the standard form
19    contract developed pursuant to paragraph (2) of this
20    subsection (e). The procurement administrator shall then
21    identify and register bidders to participate in the
22    procurement event.
23        (2) Standard contract forms and credit terms and
24    instruments. The procurement administrator, in
25    consultation with the utilities, the Commission, and other
26    interested parties and subject to Commission oversight,

 

 

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1    shall develop and provide standard contract forms for the
2    supplier contracts that meet generally accepted industry
3    practices. Standard credit terms and instruments that meet
4    generally accepted industry practices shall be similarly
5    developed. The procurement administrator shall make
6    available to the Commission all written comments it
7    receives on the contract forms, credit terms, or
8    instruments. If the procurement administrator cannot reach
9    agreement with the applicable electric utility as to the
10    contract terms and conditions, the procurement
11    administrator must notify the Commission of any disputed
12    terms and the Commission shall resolve the dispute. The
13    terms of the contracts shall not be subject to negotiation
14    by winning bidders, and the bidders must agree to the terms
15    of the contract in advance so that winning bids are
16    selected solely on the basis of price.
17        (3) Establishment of a market-based price benchmark.
18    As part of the development of the procurement process, the
19    procurement administrator, in consultation with the
20    Commission staff, Agency staff, and the procurement
21    monitor, shall establish benchmarks for evaluating the
22    final prices in the contracts for each of the products that
23    will be procured through the procurement process. The
24    benchmarks shall be based on price data for similar
25    products for the same delivery period and same delivery
26    hub, or other delivery hubs after adjusting for that

 

 

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1    difference. The price benchmarks may also be adjusted to
2    take into account differences between the information
3    reflected in the underlying data sources and the specific
4    products and procurement process being used to procure
5    power for the Illinois utilities. The benchmarks shall be
6    confidential but shall be provided to, and will be subject
7    to Commission review and approval, prior to a procurement
8    event.
9        (4) Request for proposals competitive procurement
10    process. The procurement administrator shall design and
11    issue a request for proposals to supply electricity in
12    accordance with each utility's procurement plan, as
13    approved by the Commission. The request for proposals shall
14    set forth a procedure for sealed, binding commitment
15    bidding with pay-as-bid settlement, and provision for
16    selection of bids on the basis of price.
17        (5) A plan for implementing contingencies in the event
18    of supplier default or failure of the procurement process
19    to fully meet the expected load requirement due to
20    insufficient supplier participation, Commission rejection
21    of results, or any other cause.
22            (i) Event of supplier default: In the event of
23        supplier default, the utility shall review the
24        contract of the defaulting supplier to determine if the
25        amount of supply is 200 megawatts or greater, and if
26        there are more than 60 days remaining of the contract

 

 

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1        term. If both of these conditions are met, and the
2        default results in termination of the contract, the
3        utility shall immediately notify the Illinois Power
4        Agency that a request for proposals must be issued to
5        procure replacement power, and the procurement
6        administrator shall run an additional procurement
7        event. If the contracted supply of the defaulting
8        supplier is less than 200 megawatts or there are less
9        than 60 days remaining of the contract term, the
10        utility shall procure power and energy from the
11        applicable regional transmission organization market,
12        including ancillary services, capacity, and day-ahead
13        or real time energy, or both, for the duration of the
14        contract term to replace the contracted supply;
15        provided, however, that if a needed product is not
16        available through the regional transmission
17        organization market it shall be purchased from the
18        wholesale market.
19            (ii) Failure of the procurement process to fully
20        meet the expected load requirement: If the procurement
21        process fails to fully meet the expected load
22        requirement due to insufficient supplier participation
23        or due to a Commission rejection of the procurement
24        results, the procurement administrator, the
25        procurement monitor, and the Commission staff shall
26        meet within 10 days to analyze potential causes of low

 

 

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1        supplier interest or causes for the Commission
2        decision. If changes are identified that would likely
3        result in increased supplier participation, or that
4        would address concerns causing the Commission to
5        reject the results of the prior procurement event, the
6        procurement administrator may implement those changes
7        and rerun the request for proposals process according
8        to a schedule determined by those parties and
9        consistent with Section 1-75 of the Illinois Power
10        Agency Act and this subsection. In any event, a new
11        request for proposals process shall be implemented by
12        the procurement administrator within 90 days after the
13        determination that the procurement process has failed
14        to fully meet the expected load requirement.
15            (iii) In all cases where there is insufficient
16        supply provided under contracts awarded through the
17        procurement process to fully meet the electric
18        utility's load requirement, the utility shall meet the
19        load requirement by procuring power and energy from the
20        applicable regional transmission organization market,
21        including ancillary services, capacity, and day-ahead
22        or real time energy or both; provided, however, that if
23        a needed product is not available through the regional
24        transmission organization market it shall be purchased
25        from the wholesale market.
26        (6) The procurement process described in this

 

 

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1    subsection is exempt from the requirements of the Illinois
2    Procurement Code, pursuant to Section 20-10 of that Code.
3    (f) Within 2 business days after opening the sealed bids,
4the procurement administrator shall submit a confidential
5report to the Commission. The report shall contain the results
6of the bidding for each of the products along with the
7procurement administrator's recommendation for the acceptance
8and rejection of bids based on the price benchmark criteria and
9other factors observed in the process. The procurement monitor
10also shall submit a confidential report to the Commission
11within 2 business days after opening the sealed bids. The
12report shall contain the procurement monitor's assessment of
13bidder behavior in the process as well as an assessment of the
14procurement administrator's compliance with the procurement
15process and rules. The Commission shall review the confidential
16reports submitted by the procurement administrator and
17procurement monitor, and shall accept or reject the
18recommendations of the procurement administrator within 2
19business days after receipt of the reports.
20    (g) Within 3 business days after the Commission decision
21approving the results of a procurement event, the utility shall
22enter into binding contractual arrangements with the winning
23suppliers using the standard form contracts; except that the
24utility shall not be required either directly or indirectly to
25execute the contracts if a tariff that is consistent with
26subsection (l) of this Section has not been approved and placed

 

 

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1into effect for that utility.
2    (h) The names of the successful bidders and the load
3weighted average of the winning bid prices for each contract
4type and for each contract term shall be made available to the
5public at the time of Commission approval of a procurement
6event. The Commission, the procurement monitor, the
7procurement administrator, the Illinois Power Agency, and all
8participants in the procurement process shall maintain the
9confidentiality of all other supplier and bidding information
10in a manner consistent with all applicable laws, rules,
11regulations, and tariffs. Confidential information, including
12the confidential reports submitted by the procurement
13administrator and procurement monitor pursuant to subsection
14(f) of this Section, shall not be made publicly available and
15shall not be discoverable by any party in any proceeding,
16absent a compelling demonstration of need, nor shall those
17reports be admissible in any proceeding other than one for law
18enforcement purposes.
19    (i) Within 2 business days after a Commission decision
20approving the results of a procurement event or such other date
21as may be required by the Commission from time to time, the
22utility shall file for informational purposes with the
23Commission its actual or estimated retail supply charges, as
24applicable, by customer supply group reflecting the costs
25associated with the procurement and computed in accordance with
26the tariffs filed pursuant to subsection (l) of this Section

 

 

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1and approved by the Commission.
2    (j) Within 60 days following the effective date of this
3amendatory Act, each electric utility that on December 31, 2005
4provided electric service to at least 100,000 customers in
5Illinois shall prepare and file with the Commission an initial
6procurement plan, which shall conform in all material respects
7to the requirements of the procurement plan set forth in
8subsection (b); provided, however, that the Illinois Power
9Agency Act shall not apply to the initial procurement plan
10prepared pursuant to this subsection. The initial procurement
11plan shall identify the portfolio of power and energy products
12to be procured and delivered for the period June 2008 through
13May 2009, and shall identify the proposed procurement
14administrator, who shall have the same experience and expertise
15as is required of a procurement administrator hired pursuant to
16Section 1-75 of the Illinois Power Agency Act. Copies of the
17procurement plan shall be posted and made publicly available on
18the Commission's website. The initial procurement plan may
19include contracts for renewable resources that extend beyond
20May 2009.
21        (i) Within 14 days following filing of the initial
22    procurement plan, any person may file a detailed objection
23    with the Commission contesting the procurement plan
24    submitted by the electric utility. All objections to the
25    electric utility's plan shall be specific, supported by
26    data or other detailed analyses. The electric utility may

 

 

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1    file a response to any objections to its procurement plan
2    within 7 days after the date objections are due to be
3    filed. Within 7 days after the date the utility's response
4    is due, the Commission shall determine whether a hearing is
5    necessary. If it determines that a hearing is necessary, it
6    shall require the hearing to be completed and issue an
7    order on the procurement plan within 60 days after the
8    filing of the procurement plan by the electric utility.
9        (ii) The order shall approve or modify the procurement
10    plan, approve an independent procurement administrator,
11    and approve or modify the electric utility's tariffs that
12    are proposed with the initial procurement plan. The
13    Commission shall approve the procurement plan if the
14    Commission determines that it will ensure adequate,
15    reliable, affordable, efficient, and environmentally
16    sustainable electric service at the lowest total cost over
17    time, taking into account any benefits of price stability.
18    (k) In order to promote price stability for residential and
19small commercial customers during the transition to
20competition in Illinois, and notwithstanding any other
21provision of this Act, each electric utility subject to this
22Section shall enter into one or more multi-year financial swap
23contracts that become effective on the effective date of this
24amendatory Act. These contracts may be executed with generators
25and power marketers, including affiliated interests of the
26electric utility. These contracts shall be for a term of no

 

 

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1more than 5 years and shall, for each respective utility or for
2any Illinois electric utilities that are affiliated by virtue
3of a common parent company and that are thereby considered a
4single electric utility for purposes of this subsection (k),
5not exceed in the aggregate 3,000 megawatts for any hour of the
6year. The contracts shall be financial contracts and not energy
7sales contracts. The contracts shall be executed as
8transactions under a negotiated master agreement based on the
9form of master agreement for financial swap contracts sponsored
10by the International Swaps and Derivatives Association, Inc.
11and shall be considered pre-existing contracts in the
12utilities' procurement plans for residential and small
13commercial customers. Costs incurred pursuant to a contract
14authorized by this subsection (k) shall be deemed prudently
15incurred and reasonable in amount and the electric utility
16shall be entitled to full cost recovery pursuant to the tariffs
17filed with the Commission.
18    (k-5) In order to promote price stability for residential
19and small commercial customers during the infrastructure
20investment program described in subsection (b) of Section
2116-108.5 of this Act, and notwithstanding any other provision
22of this Act or the Illinois Power Agency Act, for each electric
23utility that serves more than one million retail customers in
24Illinois, the Illinois Power Agency shall conduct a procurement
25event within 120 days after October 26, 2011 (the effective
26date of Public Act 97-616) and may procure contracts for energy

 

 

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1and renewable energy credits for the period June 1, 2013
2through December 31, 2017 that satisfy the requirements of this
3subsection (k-5), including the benchmarks described in this
4subsection. These contracts shall be entered into as the result
5of a competitive procurement event, and, to the extent that any
6provisions of this Section or the Illinois Power Agency Act do
7not conflict with this subsection (k-5), such provisions shall
8apply to the procurement event. The energy contracts shall be
9for 24 hour by 7 day supply over a term that runs from the first
10delivery year through December 31, 2017. For a utility that
11serves over 2 million customers, the energy contracts shall be
12multi-year with pricing escalating at 2.5% per annum. The
13energy contracts may be designed as financial swaps or may
14require physical delivery.
15    Within 30 days of October 26, 2011 (the effective date of
16Public Act 97-616), each such utility shall submit to the
17Agency updated load forecasts for the period June 1, 2013
18through December 31, 2017. The megawatt volume of the contracts
19shall be based on the updated load forecasts of the minimum
20monthly on-peak or off-peak average load requirements shown in
21the forecasts, taking into account any existing energy
22contracts in effect as well as the expected migration of the
23utility's customers to alternative retail electric suppliers.
24The renewable energy credit volume shall be based on the number
25of credits that would satisfy the requirements of subsection
26(c) of Section 1-75 of the Illinois Power Agency Act, subject

 

 

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1to the rate impact caps and other provisions of subsection (c)
2of Section 1-75 of the Illinois Power Agency Act. The
3evaluation of contract bids in the competitive procurement
4events for energy and for renewable energy credits shall
5incorporate price benchmarks set collaboratively by the
6Agency, the procurement administrator, the staff of the
7Commission, and the procurement monitor. If the contracts are
8swap contracts, then they shall be executed as transactions
9under a negotiated master agreement based on the form of master
10agreement for financial swap contracts sponsored by the
11International Swaps and Derivatives Association, Inc. Costs
12incurred pursuant to a contract authorized by this subsection
13(k-5) shall be deemed prudently incurred and reasonable in
14amount and the electric utility shall be entitled to full cost
15recovery pursuant to the tariffs filed with the Commission.
16    The cost of administering the procurement event described
17in this subsection (k-5) shall be paid by the winning supplier
18or suppliers to the procurement administrator through a
19supplier fee. In the event that there is no winning supplier
20for a particular utility, such utility will pay the procurement
21administrator for the costs associated with the procurement
22event, and those costs shall not be a recoverable expense.
23Nothing in this subsection (k-5) is intended to alter the
24recovery of costs for any other procurement event.
25    (l) An electric utility shall recover its costs incurred
26under this Section, including, but not limited to, the costs of

 

 

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1procuring power and energy demand-response resources under
2this Section. The utility shall file with the initial
3procurement plan its proposed tariffs through which its costs
4of procuring power that are incurred pursuant to a
5Commission-approved procurement plan and those other costs
6identified in this subsection (l), will be recovered. The
7tariffs shall include a formula rate or charge designed to pass
8through both the costs incurred by the utility in procuring a
9supply of electric power and energy for the applicable customer
10classes with no mark-up or return on the price paid by the
11utility for that supply, plus any just and reasonable costs
12that the utility incurs in arranging and providing for the
13supply of electric power and energy. The formula rate or charge
14shall also contain provisions that ensure that its application
15does not result in over or under recovery due to changes in
16customer usage and demand patterns, and that provide for the
17correction, on at least an annual basis, of any accounting
18errors that may occur. A utility shall recover through the
19tariff all reasonable costs incurred to implement or comply
20with any procurement plan that is developed and put into effect
21pursuant to Section 1-75 of the Illinois Power Agency Act and
22this Section, including any fees assessed by the Illinois Power
23Agency, costs associated with load balancing, and contingency
24plan costs. The electric utility shall also recover its full
25costs of procuring electric supply for which it contracted
26before the effective date of this Section in conjunction with

 

 

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1the provision of full requirements service under fixed-price
2bundled service tariffs subsequent to December 31, 2006. All
3such costs shall be deemed to have been prudently incurred. The
4pass-through tariffs that are filed and approved pursuant to
5this Section shall not be subject to review under, or in any
6way limited by, Section 16-111(i) of this Act.
7    (m) The Commission has the authority to adopt rules to
8carry out the provisions of this Section. For the public
9interest, safety, and welfare, the Commission also has
10authority to adopt rules to carry out the provisions of this
11Section on an emergency basis immediately following the
12effective date of this amendatory Act.
13    (n) Notwithstanding any other provision of this Act, any
14affiliated electric utilities that submit a single procurement
15plan covering their combined needs may procure for those
16combined needs in conjunction with that plan, and may enter
17jointly into power supply contracts, purchases, and other
18procurement arrangements, and allocate capacity and energy and
19cost responsibility therefor among themselves in proportion to
20their requirements.
21    (o) On or before June 1 of each year, the Commission shall
22hold an informal hearing for the purpose of receiving comments
23on the prior year's procurement process and any recommendations
24for change.
25    (p) An electric utility subject to this Section may propose
26to invest, lease, own, or operate an electric generation

 

 

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1facility as part of its procurement plan, provided the utility
2demonstrates that such facility is the least-cost option to
3provide electric service to eligible retail customers. If the
4facility is shown to be the least-cost option and is included
5in a procurement plan prepared in accordance with Section 1-75
6of the Illinois Power Agency Act and this Section, then the
7electric utility shall make a filing pursuant to Section 8-406
8of this Act, and may request of the Commission any statutory
9relief required thereunder. If the Commission grants all of the
10necessary approvals for the proposed facility, such supply
11shall thereafter be considered as a pre-existing contract under
12subsection (b) of this Section. The Commission shall in any
13order approving a proposal under this subsection specify how
14the utility will recover the prudently incurred costs of
15investing in, leasing, owning, or operating such generation
16facility through just and reasonable rates charged to eligible
17retail customers. Cost recovery for facilities included in the
18utility's procurement plan pursuant to this subsection shall
19not be subject to review under or in any way limited by the
20provisions of Section 16-111(i) of this Act. Nothing in this
21Section is intended to prohibit a utility from filing for a
22fuel adjustment clause as is otherwise permitted under Section
239-220 of this Act.
24(Source: P.A. 97-325, eff. 8-12-11; 97-616, eff. 10-26-11;
2597-813, eff. 7-13-12.)
 

 

 

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1    (220 ILCS 5/16-111.5B)
2    Sec. 16-111.5B. Provisions relating to energy efficiency
3procurement.
4    (a) Procurement Beginning in 2012, procurement plans
5prepared and filed pursuant to Section 16-111.5 of this Act
6during the years 2012 through 2014 shall be subject to the
7following additional requirements:
8        (1) The analysis included pursuant to paragraph (2) of
9    subsection (b) of Section 16-111.5 shall also include the
10    impact of energy efficiency building codes or appliance
11    standards, both current and projected.
12        (2) The procurement plan components described in
13    subsection (b) of Section 16-111.5 shall also include an
14    assessment of opportunities to expand the programs
15    promoting energy efficiency measures that have been
16    offered under plans approved pursuant to Section 8-103 of
17    this Act or to implement additional cost-effective energy
18    efficiency programs or measures.
19        (3) In addition to the information provided pursuant to
20    paragraph (1) of subsection (d) of Section 16-111.5 of this
21    Act, each Illinois utility procuring power pursuant to that
22    Section shall annually provide to the Illinois Power Agency
23    by July 15 of each year, or such other date as may be
24    required by the Commission or Agency, an assessment of
25    cost-effective energy efficiency programs or measures that
26    could be included in the procurement plan. The assessment

 

 

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1    shall include the following:
2            (A) A comprehensive energy efficiency potential
3        study for the utility's service territory that was
4        completed within the past 3 years.
5            (B) Beginning in 2014, the most recent analysis
6        submitted pursuant to Section 8-103A of this Act and
7        approved by the Commission under subsection (g) (f) of
8        Section 8-103 of this Act.
9            (C) Identification of new or expanded
10        cost-effective energy efficiency programs or measures
11        that are incremental to those included in energy
12        efficiency and demand-response plans approved by the
13        Commission pursuant to Section 8-103 of this Act and
14        that would be offered to all retail customers whose
15        electric service has not been declared competitive
16        under Section 16-113 of this Act and who are eligible
17        to purchase power and energy from the utility under
18        fixed-price bundled service tariffs, regardless of
19        whether such customers actually do purchase such power
20        and energy from the utility.
21            (D) Analysis showing that the new or expanded
22        cost-effective energy efficiency programs or measures
23        would lead to a reduction in the overall cost of
24        electric service.
25            (E) Analysis of how the cost of procuring
26        additional cost-effective energy efficiency measures

 

 

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1        compares over the life of the measures to the
2        prevailing cost of comparable supply.
3            (F) An energy savings goal, expressed in
4        megawatt-hours, for the year in which the measures will
5        be implemented.
6            (G) For each expanded or new program, the estimated
7        amount that the program may reduce the agency's need to
8        procure supply.
9        In preparing such assessments, a utility shall conduct
10    an annual solicitation process for purposes of requesting
11    proposals from third-party vendors, the results of which
12    shall be provided to the Agency as part of the assessment,
13    including documentation of all bids received. The utility
14    shall develop requests for proposals consistent with the
15    manner in which it develops requests for proposals under
16    plans approved pursuant to Section 8-103 of this Act, which
17    considers input from the Agency and interested
18    stakeholders.
19        (4) The Illinois Power Agency shall include in the
20    procurement plan prepared pursuant to paragraph (2) of
21    subsection (d) of Section 16-111.5 of this Act energy
22    efficiency programs and measures it determines are
23    cost-effective and the associated annual energy savings
24    goal included in the annual solicitation process and
25    assessment submitted pursuant to paragraph (3) of this
26    subsection (a).

 

 

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1        (5) Pursuant to paragraph (4) of subsection (d) of
2    Section 16-111.5 of this Act, the Commission shall also
3    approve the energy efficiency programs and measures
4    included in the procurement plan, including the annual
5    energy savings goal, if the Commission determines they
6    fully capture the potential for all achievable
7    cost-effective savings, to the extent practicable, and
8    otherwise satisfy the requirements of Section 8-103 of this
9    Act.
10        In the event the Commission approves the procurement of
11    additional energy efficiency, it shall reduce the amount of
12    power to be procured under the procurement plan to reflect
13    the additional energy efficiency and shall direct the
14    utility to undertake the procurement of such energy
15    efficiency, which shall not be subject to the requirements
16    of subsection (e) of Section 16-111.5 of this Act. The
17    utility shall consider input from the Agency and interested
18    stakeholders on the procurement and administration
19    process. The requirements set forth in paragraphs (1)
20    through (5) of this subsection (a) shall terminate after
21    the filing of the procurement plan in 2014, and no energy
22    efficiency shall be procured by the Agency thereafter.
23    Energy efficiency programs approved previously pursuant to
24    this Section shall terminate no later than December 31,
25    2017.
26        (6) An electric utility shall recover its costs

 

 

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1    incurred under this Section related to the implementation
2    of energy efficiency programs and measures approved by the
3    Commission in its order approving the procurement plan
4    under Section 16-111.5 of this Act, including, but not
5    limited to, all costs associated with complying with this
6    Section and all start-up and administrative costs and the
7    costs for any evaluation, measurement, and verification of
8    the measures, from all retail customers whose electric
9    service has not been declared competitive under Section
10    16-113 of this Act and who are eligible to purchase power
11    and energy from the utility under fixed-price bundled
12    service tariffs, regardless of whether such customers
13    actually do purchase such power and energy from the utility
14    through the automatic adjustment clause tariff established
15    pursuant to Section 8-103 of this Act, provided, however,
16    that the limitations described in subsection (d) of that
17    Section shall not apply to the costs incurred pursuant to
18    this Section or Section 16-111.7 of this Act.
19    (b) For purposes of this Section, the term "energy
20efficiency" shall have the meaning set forth in Section 1-10 of
21the Illinois Power Agency Act, and the term "cost-effective"
22shall have the meaning set forth in subsection (a) of Section
238-103 of this Act.
24(Source: P.A. 97-616, eff. 10-26-11; 97-824, eff. 7-18-12.)
 
25    (220 ILCS 5/16-115D)

 

 

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1    Sec. 16-115D. Renewable portfolio standard for alternative
2retail electric suppliers and electric utilities operating
3outside their service territories.
4    (a) An alternative retail electric supplier shall be
5responsible for procuring cost-effective renewable energy
6resources as required under item (5) of subsection (d) of
7Section 16-115 of this Act as outlined herein:
8        (1) The definition of renewable energy resources
9    contained in Section 1-10 of the Illinois Power Agency Act
10    applies to all renewable energy resources required to be
11    procured by alternative retail electric suppliers.
12        (2) The quantity of renewable energy resources shall be
13    measured as a percentage of the actual amount of metered
14    electricity (megawatt-hours) delivered by the alternative
15    retail electric supplier to Illinois retail customers
16    during the 12-month period June 1 through May 31,
17    commencing June 1, 2009, and the comparable 12-month period
18    in each year thereafter except as provided in item (6) of
19    this subsection (a).
20        (3) The quantity of renewable energy resources shall be
21    in amounts at least equal to the annual percentages set
22    forth in item (1) of subsection (c) of Section 1-75 of the
23    Illinois Power Agency Act. At least 60% of the renewable
24    energy resources procured pursuant to items (1) through (3)
25    of subsection (b) of this Section shall come from wind
26    generation and, starting June 1, 2015, at least 6% of the

 

 

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1    renewable energy resources procured pursuant to items (1)
2    through (3) of subsection (b) of this Section shall come
3    from solar photovoltaics. If, in any given year, an
4    alternative retail electric supplier does not purchase at
5    least these levels of renewable energy resources, then the
6    alternative retail electric supplier shall make
7    alternative compliance payments, as described in
8    subsection (d) of this Section.
9        (4) The quantity and source of renewable energy
10    resources shall be independently verified through the PJM
11    Environmental Information System Generation Attribute
12    Tracking System (PJM-GATS) or the Midwest Renewable Energy
13    Tracking System (M-RETS), which shall document the
14    location of generation, resource type, month, and year of
15    generation for all qualifying renewable energy resources
16    that an alternative retail electric supplier uses to comply
17    with this Section. No later than June 1, 2009, the Illinois
18    Power Agency shall provide PJM-GATS, M-RETS, and
19    alternative retail electric suppliers with all information
20    necessary to identify resources located in Illinois,
21    within states that adjoin Illinois or within portions of
22    the PJM and MISO footprint in the United States that
23    qualify under the definition of renewable energy resources
24    in Section 1-10 of the Illinois Power Agency Act for
25    compliance with this Section 16-115D. Alternative retail
26    electric suppliers shall not be subject to the requirements

 

 

09900HB3328ham001- 200 -LRB099 10473 MLM 33016 a

1    in item (3) of subsection (c) of Section 1-75 of the
2    Illinois Power Agency Act.
3        (5) All renewable energy credits used to comply with
4    this Section shall be permanently retired.
5        (6) The required procurement of renewable energy
6    resources by an alternative retail electric supplier shall
7    apply to all metered electricity delivered to Illinois
8    retail customers by the alternative retail electric
9    supplier pursuant to contracts executed or extended after
10    March 15, 2009.
11    (b) Compliance obligations.
12        (1) (b) An alternative retail electric supplier shall
13    comply with the renewable energy portfolio standards by
14    making an alternative compliance payment, as described in
15    subsection (d) of this Section, to cover:
16            (A) at least one-half of the alternative retail
17        electric supplier's compliance obligation for the
18        period prior to May 31, 2016; and
19            (B) beginning on June 1, 2016, at least 75% of the
20        alternative retail electric suppliers' compliance
21        obligation with respect to its metered electricity
22        supplied to its Illinois retail customers in customer
23        classes that, as of January 1, 2015, have not been
24        declared competitive pursuant to Section 16-113 of
25        this Act; however, for contracts with or on behalf of
26        such retail customers, entered into or extended prior

 

 

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1        to the effective date of this amendatory Act of the
2        99th General Assembly, but in no event extended beyond
3        May 31, 2017, the alternative retail electric supplier
4        shall meet at least 50% of its compliance obligation
5        with respect to such retail customers by making an
6        alternative compliance payment.
7        (2) Beginning on June 1, 2016, an alternative retail
8    electric supplier need not make any alternative compliance
9    payment to meet any portion of its compliance obligation,
10    as set forth in paragraph (3) of subsection (a) of this
11    Section, with respect to its metered electricity supplied
12    to its Illinois retail customers, but only with respect to
13    those retail customer classes that, as of January 1, 2015,
14    have been declared competitive pursuant to Section 16-113
15    of this Act, unless it chooses to meet its compliance
16    obligation under paragraph (2) of this subsection through
17    such payment.
18        (3) An alternative retail electric supplier shall use
19    any one or combination of the following means to cover the
20    remainder of the alternative retail electric supplier's
21    compliance obligation, as set forth in paragraph (3) of
22    subsection (a) of this Section, not covered by an
23    alternative compliance payment made under paragraphs (1)
24    and (2) of this subsection (b):
25        (A) (1) Generating electricity using renewable energy
26    resources identified pursuant to item (4) of subsection (a)

 

 

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1    of this Section.
2        (B) (2) Purchasing electricity generated using
3    renewable energy resources identified pursuant to item (4)
4    of subsection (a) of this Section through an energy
5    contract.
6        (C) (3) Purchasing renewable energy credits from
7    renewable energy resources identified pursuant to item (4)
8    of subsection (a) of this Section.
9        (D) (4) Making an alternative compliance payment as
10    described in subsection (d) of this Section.
11    (c) Use of renewable energy credits.
12        (1) Renewable energy credits that are not used by an
13    alternative retail electric supplier to comply with a
14    renewable portfolio standard in a compliance year may be
15    banked and carried forward up to 2 12-month compliance
16    periods after the compliance period in which the credit was
17    generated for the purpose of complying with a renewable
18    portfolio standard in those 2 subsequent compliance
19    periods. For the 2009-2010 and 2010-2011 compliance
20    periods, an alternative retail electric supplier may use
21    renewable credits generated after December 31, 2008 and
22    before June 1, 2009 to comply with this Section.
23        (2) An alternative retail electric supplier is
24    responsible for demonstrating that a renewable energy
25    credit used to comply with a renewable portfolio standard
26    is derived from a renewable energy resource and that the

 

 

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1    alternative retail electric supplier has not used, traded,
2    sold, or otherwise transferred the credit.
3        (3) The same renewable energy credit may be used by an
4    alternative retail electric supplier to comply with a
5    federal renewable portfolio standard and a renewable
6    portfolio standard established under this Act. An
7    alternative retail electric supplier that uses a renewable
8    energy credit to comply with a renewable portfolio standard
9    imposed by any other state may not use the same credit to
10    comply with a renewable portfolio standard established
11    under this Act.
12    (d) Alternative compliance payments.
13        (1) The Commission shall establish and post on its
14    website, within 5 business days after entering an order
15    approving a procurement plan pursuant to Section 1-75 of
16    the Illinois Power Agency Act, maximum alternative
17    compliance payment rates, expressed on a per kilowatt-hour
18    basis, that will be applicable in the first compliance
19    period following the plan approval. A separate maximum
20    alternative compliance payment rate shall be established
21    for the service territory of each electric utility that is
22    subject to subsection (c) of Section 1-75 of the Illinois
23    Power Agency Act. Each maximum alternative compliance
24    payment rate shall be equal to the maximum allowable annual
25    estimated average net increase due to the costs of the
26    utility's purchase of renewable energy resources included

 

 

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1    in the amounts paid by eligible retail customers in
2    connection with electric service, as described in item (2)
3    of subsection (c) of Section 1-75 of the Illinois Power
4    Agency Act for the compliance period, and as established in
5    the approved procurement plan. Following each procurement
6    event through which renewable energy resources are
7    purchased for one or more of these utilities for the
8    compliance period, the Commission shall establish and post
9    on its website estimates of the alternative compliance
10    payment rates, expressed on a per kilowatt-hour basis, that
11    shall apply for that compliance period. Posting of the
12    estimates shall occur no later than 10 business days
13    following the procurement event, however, the Commission
14    shall not be required to establish and post such estimates
15    more often than once per calendar month. By July 1 of each
16    year, the Commission shall establish and post on its
17    website the actual alternative compliance payment rates
18    for the preceding compliance year. The Commission shall
19    make available to alternative retail electric suppliers
20    subject to this Section the average cost and quantity for
21    the compliance year, the estimated average cost for each
22    subsequent compliance year, and the anticipated quantity
23    for each subsequent compliance year for the duration of
24    such executed renewable energy contracts which will impact
25    the alternative compliance payment. For compliance years
26    beginning prior to June 1, 2014, each alternative

 

 

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1    compliance payment rate shall be equal to the total amount
2    of dollars that the utility contracted to spend on
3    renewable resources, excepting the additional incremental
4    cost attributable to solar resources, for the compliance
5    period divided by the forecasted load of eligible retail
6    customers, at the customers' meters, as previously
7    established in the Commission-approved procurement plan
8    for that compliance year. For compliance years commencing
9    on or after June 1, 2014, each alternative compliance
10    payment rate shall be equal to the total amount of dollars
11    that the utility contracted to spend on all renewable
12    resources for the compliance period divided by the
13    forecasted load of eligible retail customers, at the
14    customers' meters, as previously established in the
15    Commission-approved procurement plan for that compliance
16    year. The actual alternative compliance payment rates may
17    not exceed the maximum alternative compliance payment
18    rates established for the compliance period. For purposes
19    of this subsection (d), the term "eligible retail
20    customers" has the same meaning as found in Section
21    16-111.5 of this Act.
22        (2) In any given compliance year, an alternative retail
23    electric supplier may elect to use alternative compliance
24    payments to comply with all or a part of the applicable
25    renewable portfolio standard. In the event that an
26    alternative retail electric supplier elects to make

 

 

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1    alternative compliance payments to comply with all or a
2    part of the applicable renewable portfolio standard, such
3    payments shall be made by September 1, 2010 for the period
4    of June 1, 2009 to May 1, 2010 and by September 1 of each
5    year thereafter for the subsequent compliance period, in
6    the manner and form as determined by the Commission. Any
7    election by an alternative retail electric supplier to use
8    alternative compliance payments is subject to review by the
9    Commission under subsection (e) of this Section.
10        (3) An alternative retail electric supplier's
11    alternative compliance payments shall be computed
12    separately for each electric utility's service territory
13    within which the alternative retail electric supplier
14    provided retail service during the compliance period,
15    provided that the electric utility was subject to
16    subsection (c) of Section 1-75 of the Illinois Power Agency
17