SB1652 EnrolledLRB097 09323 ASK 49458 b

1    AN ACT concerning public utilities.
 
2    Be it enacted by the People of the State of Illinois,
3represented in the General Assembly:
 
4    Section 5. The Illinois Power Agency Act is amended by
5changing Section 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.
17    "Authority" means the Illinois Finance Authority.
18    "Clean coal facility" means an electric generating
19facility that uses primarily coal as a feedstock and that
20captures and sequesters carbon emissions at the following
21levels: at least 50% of the total carbon emissions that the
22facility would otherwise emit if, at the time construction
23commences, the facility is scheduled to commence operation

 

 

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

 

 

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

 

 

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

 

 

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1of electricity or natural gas required to achieve a given end
2use.
3    "Electric utility" has the same definition as found in
4Section 16-102 of the Public Utilities Act.
5    "Facility" means an electric generating unit or a
6co-generating unit that produces electricity along with
7related equipment necessary to connect the facility to an
8electric transmission or distribution system.
9    "Governmental aggregator" means one or more units of local
10government that individually or collectively procure
11electricity to serve residential retail electrical loads
12located within its or their jurisdiction.
13    "Local government" means a unit of local government as
14defined in Article VII of Section 1 of the Illinois
15Constitution.
16    "Municipality" means a city, village, or incorporated
17town.
18    "Person" means any natural person, firm, partnership,
19corporation, either domestic or foreign, company, association,
20limited liability company, joint stock company, or association
21and includes any trustee, receiver, assignee, or personal
22representative thereof.
23    "Project" means the planning, bidding, and construction of
24a facility.
25    "Public utility" has the same definition as found in
26Section 3-105 of the Public Utilities Act.

 

 

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1    "Real property" means any interest in land together with
2all structures, fixtures, and improvements thereon, including
3lands under water and riparian rights, any easements,
4covenants, licenses, leases, rights-of-way, uses, and other
5interests, together with any liens, judgments, mortgages, or
6other claims or security interests related to real property.
7    "Renewable energy credit" means a tradable credit that
8represents the environmental attributes of a certain amount of
9energy produced from a renewable energy resource.
10    "Renewable energy resources" includes energy and its
11associated renewable energy credit or renewable energy credits
12from wind, solar thermal energy, photovoltaic cells and panels,
13biodiesel, crops and untreated and unadulterated organic waste
14biomass, tree waste, hydropower that does not involve new
15construction or significant expansion of hydropower dams, and
16other alternative sources of environmentally preferable
17energy. For purposes of this Act, landfill gas produced in the
18State is considered a renewable energy resource. "Renewable
19energy resources" does not include the incineration or burning
20of tires, garbage, general household, institutional, and
21commercial waste, industrial lunchroom or office waste,
22landscape waste other than tree waste, railroad crossties,
23utility poles, or construction or demolition debris, other than
24untreated and unadulterated waste wood.
25    "Revenue bond" means any bond, note, or other evidence of
26indebtedness issued by the Authority, the principal and

 

 

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1interest of which is payable solely from revenues or income
2derived from any project or activity of the Agency.
3    "Sequester" means permanent storage of carbon dioxide by
4injecting it into a saline aquifer, a depleted gas reservoir,
5or an oil reservoir, directly or through an enhanced oil
6recovery process that may involve intermediate storage in a
7salt dome.
8    "Servicing agreement" means (i) in the case of an electric
9utility, an agreement between the owner of a clean coal
10facility and such electric utility, which agreement shall have
11terms and conditions meeting the requirements of paragraph (3)
12of subsection (d) of Section 1-75, and (ii) in the case of an
13alternative retail electric supplier, an agreement between the
14owner of a clean coal facility and such alternative retail
15electric supplier, which agreement shall have terms and
16conditions meeting the requirements of Section 16-115(d)(5) of
17the Public Utilities Act.
18    "Substitute natural gas" or "SNG" means a gas manufactured
19by gasification of hydrocarbon feedstock, which is
20substantially interchangeable in use and distribution with
21conventional natural gas.
22    "Total resource cost test" or "TRC test" means a standard
23that is met if, for an investment in energy efficiency or
24demand-response measures, the benefit-cost ratio is greater
25than one. The benefit-cost ratio is the ratio of the net
26present value of the total benefits of the program to the net

 

 

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1present value of the total costs as calculated over the
2lifetime of the measures. A total resource cost test compares
3the sum of avoided electric utility costs, representing the
4benefits that accrue to the system and the participant in the
5delivery of those efficiency measures, as well as other
6quantifiable societal benefits, including avoided natural gas
7utility costs, to the sum of all incremental costs of end-use
8measures that are implemented due to the program (including
9both utility and participant contributions), plus costs to
10administer, deliver, and evaluate each demand-side program, to
11quantify the net savings obtained by substituting the
12demand-side program for supply resources. In calculating
13avoided costs of power and energy that an electric utility
14would otherwise have had to acquire, reasonable estimates shall
15be included of financial costs likely to be imposed by future
16regulations and legislation on emissions of greenhouse gases.
17(Source: P.A. 95-481, eff. 8-28-07; 95-913, eff. 1-1-09;
1895-1027, eff. 6-1-09; 96-33, eff. 7-10-09; 96-159, eff.
198-10-09; 96-784, eff. 8-28-09; 96-1000, eff. 7-2-10.)
 
20    (20 ILCS 3855/1-56)
21    Sec. 1-56. Illinois Power Agency Renewable Energy
22Resources Fund.
23    (a) The Illinois Power Agency Renewable Energy Resources
24Fund is created as a special fund in the State treasury.
25    (b) The Illinois Power Agency Renewable Energy Resources

 

 

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1Fund shall be administered by the Agency to procure renewable
2energy resources. Prior to June 1, 2011, resources procured
3pursuant to this Section shall be procured from facilities
4located in Illinois, provided the resources are available from
5those facilities. If resources are not available in Illinois,
6then they shall be procured in states that adjoin Illinois. If
7resources are not available in Illinois or in states that
8adjoin Illinois, then they may be purchased elsewhere.
9Beginning June 1, 2011, resources procured pursuant to this
10Section shall be procured from facilities located in Illinois
11or states that adjoin Illinois. If resources are not available
12in Illinois or in states that adjoin Illinois, then they may be
13procured elsewhere. To the extent available, at least 75% of
14these renewable energy resources shall come from wind
15generation. Of the renewable energy resources procured
16pursuant to this Section at least the following specified
17percentages shall come from photovoltaics on the following
18schedule: 0.5% by June 1, 2012; 1.5% by June 1, 2013; 3% by
19June 1, 2014; and 6% by June 1, 2015 and thereafter. Of the
20renewable energy resources procured pursuant to this Section,
21at least the following percentages shall come from distributed
22renewable energy generation devices: 0.5% by June 1, 2013,
230.75% by June 1, 2014, and 1% by June 1, 2015 and thereafter.
24To the extent available, half of the renewable energy resources
25procured from distributed renewable energy generation shall
26come from devices of less than 25 kilowatts in nameplate

 

 

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1capacity. Renewable energy resources procured from distributed
2generation devices may also count towards the required
3percentages for wind and solar photovoltaics. Procurement of
4renewable energy resources from distributed renewable energy
5generation devices shall be done on an annual basis through
6multi-year contracts of no less than 5 years, and shall consist
7solely of renewable energy credits.
8    The Agency shall create credit requirements for suppliers
9of distributed renewable energy. In order to minimize the
10administrative burden on contracting entities, the Agency
11shall solicit the use of third-party organizations to aggregate
12distributed renewable energy into groups of no less than one
13megawatt in installed capacity. These third-party
14organizations shall administer contracts with individual
15distributed renewable energy generation device owners. An
16individual distributed renewable energy generation device
17owner shall have the ability to measure the output of his or
18her distributed renewable energy generation device.
19    (c) The Agency shall procure renewable energy resources at
20least once each year in conjunction with a procurement event
21for electric utilities required to comply with Section 1-75 of
22the Act and shall, whenever possible, enter into long-term
23contracts on an annual basis for a portion of the incremental
24requirement for the given procurement year.
25    (d) The price paid to procure renewable energy credits
26using monies from the Illinois Power Agency Renewable Energy

 

 

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1Resources Fund shall not exceed the winning bid prices paid for
2like resources procured for electric utilities required to
3comply with Section 1-75 of this Act.
4    (e) All renewable energy credits procured using monies from
5the Illinois Power Agency Renewable Energy Resources Fund shall
6be permanently retired.
7    (f) The procurement process described in this Section is
8exempt from the requirements of the Illinois Procurement Code,
9pursuant to Section 20-10 of that Code.
10    (g) All disbursements from the Illinois Power Agency
11Renewable Energy Resources Fund shall be made only upon
12warrants of the Comptroller drawn upon the Treasurer as
13custodian of the Fund upon vouchers signed by the Director or
14by the person or persons designated by the Director for that
15purpose. The Comptroller is authorized to draw the warrant upon
16vouchers so signed. The Treasurer shall accept all warrants so
17signed and shall be released from liability for all payments
18made on those warrants.
19    (h) The Illinois Power Agency Renewable Energy Resources
20Fund shall not be subject to sweeps, administrative charges, or
21chargebacks, including, but not limited to, those authorized
22under Section 8h of the State Finance Act, that would in any
23way result in the transfer of any funds from this Fund to any
24other fund of this State or in having any such funds utilized
25for any purpose other than the express purposes set forth in
26this Section.

 

 

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1(Source: P.A. 96-159, eff. 8-10-09; 96-1000, eff. 7-2-10;
296-1437, eff. 8-17-10.)
 
3    (20 ILCS 3855/1-75)
4    Sec. 1-75. Planning and Procurement Bureau. The Planning
5and Procurement Bureau has the following duties and
6responsibilities:
7        (a) The Planning and Procurement Bureau shall each
8    year, beginning in 2008, develop procurement plans and
9    conduct competitive procurement processes in accordance
10    with the requirements of Section 16-111.5 of the Public
11    Utilities Act for the eligible retail customers of electric
12    utilities that on December 31, 2005 provided electric
13    service to at least 100,000 customers in Illinois. For the
14    purposes of this Section, the term "eligible retail
15    customers" has the same definition as found in Section
16    16-111.5(a) of the Public Utilities Act.
17            (1) The Agency shall each year, beginning in 2008,
18        as needed, issue a request for qualifications for
19        experts or expert consulting firms to develop the
20        procurement plans in accordance with Section 16-111.5
21        of the Public Utilities Act. In order to qualify an
22        expert or expert consulting firm must have:
23                (A) direct previous experience assembling
24            large-scale power supply plans or portfolios for
25            end-use customers;

 

 

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

 

 

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

 

 

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

 

 

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

 

 

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

 

 

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1        2013, 0.75% by June 1, 2014, and 1% by June 1, 2015 and
2        thereafter. To the extent available, half of the
3        renewable energy resources procured from distributed
4        renewable energy generation shall come from devices of
5        less than 25 kilowatts in nameplate capacity.
6        Renewable energy resources procured from distributed
7        generation devices may also count towards the required
8        percentages for wind and solar photovoltaics.
9        Procurement of renewable energy resources from
10        distributed renewable energy generation devices shall
11        be done on an annual basis through multi-year contracts
12        of no less than 5 years, and shall consist solely of
13        renewable energy credits.
14            The Agency shall create credit requirements for
15        suppliers of distributed renewable energy. In order to
16        minimize the administrative burden on contracting
17        entities, the Agency shall solicit the use of
18        third-party organizations to aggregate distributed
19        renewable energy into groups of no less than one
20        megawatt in installed capacity. These third-party
21        organizations shall administer contracts with
22        individual distributed renewable energy generation
23        device owners. An individual distributed renewable
24        energy generation device owner shall have the ability
25        to measure the output of his or her distributed
26        renewable energy generation device. For purposes of

 

 

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1        this subsection (c), "cost-effective" means that the
2        costs of procuring renewable energy resources do not
3        cause the limit stated in paragraph (2) of this
4        subsection (c) to be exceeded and do not exceed
5        benchmarks based on market prices for renewable energy
6        resources in the region, which shall be developed by
7        the procurement administrator, in consultation with
8        the Commission staff, Agency staff, and the
9        procurement monitor and shall be subject to Commission
10        review and approval.
11            (2) For purposes of this subsection (c), the
12        required procurement of cost-effective renewable
13        energy resources for a particular year shall be
14        measured as a percentage of the actual amount of
15        electricity (megawatt-hours) supplied by the electric
16        utility to eligible retail customers in the planning
17        year ending immediately prior to the procurement. For
18        purposes of this subsection (c), the amount paid per
19        kilowatthour means the total amount paid for electric
20        service expressed on a per kilowatthour basis. For
21        purposes of this subsection (c), the total amount paid
22        for electric service includes without limitation
23        amounts paid for supply, transmission, distribution,
24        surcharges, and add-on taxes.
25            Notwithstanding the requirements of this
26        subsection (c), the total of renewable energy

 

 

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

 

 

SB1652 Enrolled- 21 -LRB097 09323 ASK 49458 b

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

 

 

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

 

 

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1        a result of the application of the alternative
2        compliance payment rate or rates to such customers,
3        and, beginning in 2011, the utility shall include in
4        the information provided under item (1) of subsection
5        (d) of Section 16-111.5 of the Public Utilities Act the
6        amounts collected under the alternative compliance
7        payment rate or rates for the prior year ending May 31.
8        Notwithstanding any limitation on the procurement of
9        renewable energy resources imposed by item (2) of this
10        subsection (c), the Agency shall increase its spending
11        on the purchase of renewable energy resources to be
12        procured by the electric utility for the next plan year
13        by an amount equal to the amounts collected by the
14        utility under the alternative compliance payment rate
15        or rates in the prior year ending May 31.
16    (d) Clean coal portfolio standard.
17        (1) The procurement plans shall include electricity
18    generated using clean coal. Each utility shall enter into
19    one or more sourcing agreements with the initial clean coal
20    facility, as provided in paragraph (3) of this subsection
21    (d), covering electricity generated by the initial clean
22    coal facility representing at least 5% of each utility's
23    total supply to serve the load of eligible retail customers
24    in 2015 and each year thereafter, as described in paragraph
25    (3) of this subsection (d), subject to the limits specified
26    in paragraph (2) of this subsection (d). It is the goal of

 

 

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

 

 

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

 

 

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

 

 

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1            by those customers during the year ending May 31,
2            2009 or (ii) the incremental amount per
3            kilowatthour paid for these resources in 2013.
4            These requirements may be altered only as provided
5            by statute. No later than June 30, 2015, the
6            Commission shall review the limitation on the
7            total amount paid under sourcing agreements, if
8            any, with clean coal facilities pursuant to this
9            subsection (d) and report to the General Assembly
10            its findings as to whether that limitation unduly
11            constrains the amount of electricity generated by
12            cost-effective clean coal facilities that is
13            covered by sourcing agreements.
14        (3) Initial clean coal facility. In order to promote
15    development of clean coal facilities in Illinois, each
16    electric utility subject to this Section shall execute a
17    sourcing agreement to source electricity from a proposed
18    clean coal facility in Illinois (the "initial clean coal
19    facility") that will have a nameplate capacity of at least
20    500 MW when commercial operation commences, that has a
21    final Clean Air Act permit on the effective date of this
22    amendatory Act of the 95th General Assembly, and that will
23    meet the definition of clean coal facility in Section 1-10
24    of this Act when commercial operation commences. The
25    sourcing agreements with this initial clean coal facility
26    shall be subject to both approval of the initial clean coal

 

 

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1    facility by the General Assembly and satisfaction of the
2    requirements of paragraph (4) of this subsection (d) and
3    shall be executed within 90 days after any such approval by
4    the General Assembly. The Agency and the Commission shall
5    have authority to inspect all books and records associated
6    with the initial clean coal facility during the term of
7    such a sourcing agreement. A utility's sourcing agreement
8    for electricity produced by the initial clean coal facility
9    shall include:
10            (A) a formula contractual price (the "contract
11        price") approved pursuant to paragraph (4) of this
12        subsection (d), which shall:
13                (i) be determined using a cost of service
14            methodology employing either a level or deferred
15            capital recovery component, based on a capital
16            structure consisting of 45% equity and 55% debt,
17            and a return on equity as may be approved by the
18            Federal Energy Regulatory Commission, which in any
19            case may not exceed the lower of 11.5% or the rate
20            of return approved by the General Assembly
21            pursuant to paragraph (4) of this subsection (d);
22            and
23                (ii) provide that all miscellaneous net
24            revenue, including but not limited to net revenue
25            from the sale of emission allowances, if any,
26            substitute natural gas, if any, grants or other

 

 

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

 

 

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

 

 

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

 

 

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

 

 

SB1652 Enrolled- 33 -LRB097 09323 ASK 49458 b

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

 

 

SB1652 Enrolled- 34 -LRB097 09323 ASK 49458 b

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

 

 

SB1652 Enrolled- 35 -LRB097 09323 ASK 49458 b

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

 

 

SB1652 Enrolled- 36 -LRB097 09323 ASK 49458 b

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

 

 

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

 

 

SB1652 Enrolled- 38 -LRB097 09323 ASK 49458 b

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

 

 

SB1652 Enrolled- 39 -LRB097 09323 ASK 49458 b

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

 

 

SB1652 Enrolled- 40 -LRB097 09323 ASK 49458 b

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

 

 

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

 

 

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

 

 

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

 

 

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1    approval. The Commission shall have authority to inspect
2    all books and records associated with these clean coal
3    facilities during the term of any such contract.
4        (6) Costs incurred under this subsection (d) or
5    pursuant to a contract entered into under this subsection
6    (d) shall be deemed prudently incurred and reasonable in
7    amount and the electric utility shall be entitled to full
8    cost recovery pursuant to the tariffs filed with the
9    Commission.
10        (e) The draft procurement plans are subject to public
11    comment, as required by Section 16-111.5 of the Public
12    Utilities Act.
13        (f) The Agency shall submit the final procurement plan
14    to the Commission. The Agency shall revise a procurement
15    plan if the Commission determines that it does not meet the
16    standards set forth in Section 16-111.5 of the Public
17    Utilities Act.
18        (g) The Agency shall assess fees to each affected
19    utility to recover the costs incurred in preparation of the
20    annual procurement plan for the utility.
21        (h) The Agency shall assess fees to each bidder to
22    recover the costs incurred in connection with a competitive
23    procurement process.
24(Source: P.A. 95-481, eff. 8-28-07; 95-1027, eff. 6-1-09;
2596-159, eff. 8-10-09; 96-1437, eff. 8-17-10.)
 

 

 

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1    Section 10. The Public Utilities Act is amended by changing
2Sections 8-103, 16-107.5, 16-111.5, 16-111.7, and 16-128 and by
3adding Sections 8-103A, 16-108.5, 16-108.6, 16-108.7,
416-108.8, 16-111.5B, and 16-128A as follows:
 
5    (220 ILCS 5/8-103)
6    Sec. 8-103. Energy efficiency and demand-response
7measures.
8    (a) It is the policy of the State that electric utilities
9are required to use cost-effective energy efficiency and
10demand-response measures to reduce delivery load. Requiring
11investment in cost-effective energy efficiency and
12demand-response measures will reduce direct and indirect costs
13to consumers by decreasing environmental impacts and by
14avoiding or delaying the need for new generation, transmission,
15and distribution infrastructure. It serves the public interest
16to allow electric utilities to recover costs for reasonably and
17prudently incurred expenses for energy efficiency and
18demand-response measures. As used in this Section,
19"cost-effective" means that the measures satisfy the total
20resource cost test. The low-income measures described in
21subsection (f)(4) of this Section shall not be required to meet
22the total resource cost test. For purposes of this Section, the
23terms "energy-efficiency", "demand-response", "electric
24utility", and "total resource cost test" shall have the
25meanings set forth in the Illinois Power Agency Act. For

 

 

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1purposes of this Section, the amount per kilowatthour means the
2total amount paid for electric service expressed on a per
3kilowatthour basis. For purposes of this Section, the total
4amount paid for electric service includes without limitation
5estimated amounts paid for supply, transmission, distribution,
6surcharges, and add-on-taxes.
7    (b) Electric utilities shall implement cost-effective
8energy efficiency measures to meet the following incremental
9annual energy savings goals:
10        (1) 0.2% of energy delivered in the year commencing
11    June 1, 2008;
12        (2) 0.4% of energy delivered in the year commencing
13    June 1, 2009;
14        (3) 0.6% of energy delivered in the year commencing
15    June 1, 2010;
16        (4) 0.8% of energy delivered in the year commencing
17    June 1, 2011;
18        (5) 1% of energy delivered in the year commencing June
19    1, 2012;
20        (6) 1.4% of energy delivered in the year commencing
21    June 1, 2013;
22        (7) 1.8% of energy delivered in the year commencing
23    June 1, 2014; and
24        (8) 2% of energy delivered in the year commencing June
25    1, 2015 and each year thereafter.
26    (c) Electric utilities shall implement cost-effective

 

 

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1demand-response measures to reduce peak demand by 0.1% over the
2prior year for eligible retail customers, as defined in Section
316-111.5 of this Act, and for customers that elect hourly
4service from the utility pursuant to Section 16-107 of this
5Act, provided those customers have not been declared
6competitive. This requirement commences June 1, 2008 and
7continues for 10 years.
8    (d) Notwithstanding the requirements of subsections (b)
9and (c) of this Section, an electric utility shall reduce the
10amount of energy efficiency and demand-response measures
11implemented in any single year by an amount necessary to limit
12the estimated average increase in the amounts paid by retail
13customers in connection with electric service due to the cost
14of those measures to:
15        (1) in 2008, no more than 0.5% of the amount paid per
16    kilowatthour by those customers during the year ending May
17    31, 2007;
18        (2) in 2009, the greater of an additional 0.5% of the
19    amount paid per kilowatthour by those customers during the
20    year ending May 31, 2008 or 1% of the amount paid per
21    kilowatthour by those customers during the year ending May
22    31, 2007;
23        (3) in 2010, the greater of an additional 0.5% of the
24    amount paid per kilowatthour by those customers during the
25    year ending May 31, 2009 or 1.5% of the amount paid per
26    kilowatthour by those customers during the year ending May

 

 

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1    31, 2007;
2        (4) in 2011, the greater of an additional 0.5% of the
3    amount paid per kilowatthour by those customers during the
4    year ending May 31, 2010 or 2% of the amount paid per
5    kilowatthour by those customers during the year ending May
6    31, 2007; and
7        (5) thereafter, the amount of energy efficiency and
8    demand-response measures implemented for any single year
9    shall be reduced by an amount necessary to limit the
10    estimated average net increase due to the cost of these
11    measures included in the amounts paid by eligible retail
12    customers in connection with electric service to no more
13    than the greater of 2.015% of the amount paid per
14    kilowatthour by those customers during the year ending May
15    31, 2007 or the incremental amount per kilowatthour paid
16    for these measures in 2011.
17    No later than June 30, 2011, the Commission shall review
18the limitation on the amount of energy efficiency and
19demand-response measures implemented pursuant to this Section
20and report to the General Assembly its findings as to whether
21that limitation unduly constrains the procurement of energy
22efficiency and demand-response measures.
23    (e) Electric utilities shall be responsible for overseeing
24the design, development, and filing of energy efficiency and
25demand-response plans with the Commission. Electric utilities
26shall implement 100% of the demand-response measures in the

 

 

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

 

 

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1demand-response measures in the State shall be permitted to
2recover costs of those measures through an automatic adjustment
3clause tariff filed with and approved by the Commission. The
4tariff shall be established outside the context of a general
5rate case. Each year the Commission shall initiate a review to
6reconcile any amounts collected with the actual costs and to
7determine the required adjustment to the annual tariff factor
8to match annual expenditures.
9    Each utility shall include, in its recovery of costs, the
10costs estimated for both the utility's and the Department's
11implementation of energy efficiency and demand-response
12measures. Costs collected by the utility for measures
13implemented by the Department shall be submitted to the
14Department pursuant to Section 605-323 of the Civil
15Administrative Code of Illinois and shall be used by the
16Department solely for the purpose of implementing these
17measures. A utility shall not be required to advance any moneys
18to the Department but only to forward such funds as it has
19collected. The Department shall report to the Commission on an
20annual basis regarding the costs actually incurred by the
21Department in the implementation of the measures. Any changes
22to the costs of energy efficiency measures as a result of plan
23modifications shall be appropriately reflected in amounts
24recovered by the utility and turned over to the Department.
25    The portfolio of measures, administered by both the
26utilities and the Department, shall, in combination, be

 

 

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1designed to achieve the annual savings targets described in
2subsections (b) and (c) of this Section, as modified by
3subsection (d) of this Section.
4    The utility and the Department shall agree upon a
5reasonable portfolio of measures and determine the measurable
6corresponding percentage of the savings goals associated with
7measures implemented by the utility or Department.
8    No utility shall be assessed a penalty under subsection (f)
9of this Section for failure to make a timely filing if that
10failure is the result of a lack of agreement with the
11Department with respect to the allocation of responsibilities
12or related costs or target assignments. In that case, the
13Department and the utility shall file their respective plans
14with the Commission and the Commission shall determine an
15appropriate division of measures and programs that meets the
16requirements of this Section.
17    If the Department is unable to meet incremental annual
18performance goals for the portion of the portfolio implemented
19by the Department, then the utility and the Department shall
20jointly submit a modified filing to the Commission explaining
21the performance shortfall and recommending an appropriate
22course going forward, including any program modifications that
23may be appropriate in light of the evaluations conducted under
24item (7) of subsection (f) of this Section. In this case, the
25utility obligation to collect the Department's costs and turn
26over those funds to the Department under this subsection (e)

 

 

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1shall continue only if the Commission approves the
2modifications to the plan proposed by the Department.
3    (f) No later than November 15, 2007, each electric utility
4shall file an energy efficiency and demand-response plan with
5the Commission to meet the energy efficiency and
6demand-response standards for 2008 through 2010. No later than
7October 1, 2010, each electric utility shall file an energy
8efficiency and demand-response plan with the Commission to meet
9the energy efficiency and demand-response standards for 2011
10through 2013. Every 3 years thereafter, each electric utility
11shall file, no later than September October 1, an energy
12efficiency and demand-response plan with the Commission. If a
13utility does not file such a plan by September October 1 of an
14applicable year, it shall face a penalty of $100,000 per day
15until the plan is filed. Each utility's plan shall set forth
16the utility's proposals to meet the utility's portion of the
17energy efficiency standards identified in subsection (b) and
18the demand-response standards identified in subsection (c) of
19this Section as modified by subsections (d) and (e), taking
20into account the unique circumstances of the utility's service
21territory. The Commission shall seek public comment on the
22utility's plan and shall issue an order approving or
23disapproving each plan within 5 3 months after its submission.
24If the Commission disapproves a plan, the Commission shall,
25within 30 days, describe in detail the reasons for the
26disapproval and describe a path by which the utility may file a

 

 

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1revised draft of the plan to address the Commission's concerns
2satisfactorily. If the utility does not refile with the
3Commission within 60 days, the utility shall be subject to
4penalties at a rate of $100,000 per day until the plan is
5filed. This process shall continue, and penalties shall accrue,
6until the utility has successfully filed a portfolio of energy
7efficiency and demand-response measures. Penalties shall be
8deposited into the Energy Efficiency Trust Fund. In submitting
9proposed energy efficiency and demand-response plans and
10funding levels to meet the savings goals adopted by this Act
11the utility shall:
12        (1) Demonstrate that its proposed energy efficiency
13    and demand-response measures will achieve the requirements
14    that are identified in subsections (b) and (c) of this
15    Section, as modified by subsections (d) and (e).
16        (2) Present specific proposals to implement new
17    building and appliance standards that have been placed into
18    effect.
19        (3) Present estimates of the total amount paid for
20    electric service expressed on a per kilowatthour basis
21    associated with the proposed portfolio of measures
22    designed to meet the requirements that are identified in
23    subsections (b) and (c) of this Section, as modified by
24    subsections (d) and (e).
25        (4) Coordinate with the Department to present a
26    portfolio of energy efficiency measures proportionate to

 

 

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1    the share of total annual utility revenues in Illinois from
2    households at or below 150% of the poverty level. The
3    energy efficiency programs shall be targeted to households
4    with incomes at or below 80% of area median income.
5        (5) Demonstrate that its overall portfolio of energy
6    efficiency and demand-response measures, not including
7    programs covered by item (4) of this subsection (f), are
8    cost-effective using the total resource cost test and
9    represent a diverse cross-section of opportunities for
10    customers of all rate classes to participate in the
11    programs.
12        (6) Include a proposed cost-recovery tariff mechanism
13    to fund the proposed energy efficiency and demand-response
14    measures and to ensure the recovery of the prudently and
15    reasonably incurred costs of Commission-approved programs.
16        (7) Provide for an annual independent evaluation of the
17    performance of the cost-effectiveness of the utility's
18    portfolio of measures and the Department's portfolio of
19    measures, as well as a full review of the 3-year results of
20    the broader net program impacts and, to the extent
21    practical, for adjustment of the measures on a
22    going-forward basis as a result of the evaluations. The
23    resources dedicated to evaluation shall not exceed 3% of
24    portfolio resources in any given year.
25    (g) No more than 3% of energy efficiency and
26demand-response program revenue may be allocated for

 

 

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1demonstration of breakthrough equipment and devices.
2    (h) This Section does not apply to an electric utility that
3on December 31, 2005 provided electric service to fewer than
4100,000 customers in Illinois.
5    (i) If, after 2 years, an electric utility fails to meet
6the efficiency standard specified in subsection (b) of this
7Section, as modified by subsections (d) and (e), it shall make
8a contribution to the Low-Income Home Energy Assistance
9Program. The combined total liability for failure to meet the
10goal shall be $1,000,000, which shall be assessed as follows: a
11large electric utility shall pay $665,000, and a medium
12electric utility shall pay $335,000. If, after 3 years, an
13electric utility fails to meet the efficiency standard
14specified in subsection (b) of this Section, as modified by
15subsections (d) and (e), it shall make a contribution to the
16Low-Income Home Energy Assistance Program. The combined total
17liability for failure to meet the goal shall be $1,000,000,
18which shall be assessed as follows: a large electric utility
19shall pay $665,000, and a medium electric utility shall pay
20$335,000. In addition, the responsibility for implementing the
21energy efficiency measures of the utility making the payment
22shall be transferred to the Illinois Power Agency if, after 3
23years, or in any subsequent 3-year period, the utility fails to
24meet the efficiency standard specified in subsection (b) of
25this Section, as modified by subsections (d) and (e). The
26Agency shall implement a competitive procurement program to

 

 

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1procure resources necessary to meet the standards specified in
2this Section as modified by subsections (d) and (e), with costs
3for those resources to be recovered in the same manner as
4products purchased through the procurement plan as provided in
5Section 16-111.5. The Director shall implement this
6requirement in connection with the procurement plan as provided
7in Section 16-111.5.
8    For purposes of this Section, (i) a "large electric
9utility" is an electric utility that, on December 31, 2005,
10served more than 2,000,000 electric customers in Illinois; (ii)
11a "medium electric utility" is an electric utility that, on
12December 31, 2005, served 2,000,000 or fewer but more than
13100,000 electric customers in Illinois; and (iii) Illinois
14electric utilities that are affiliated by virtue of a common
15parent company are considered a single electric utility.
16    (j) If, after 3 years, or any subsequent 3-year period, the
17Department fails to implement the Department's share of energy
18efficiency measures required by the standards in subsection
19(b), then the Illinois Power Agency may assume responsibility
20for and control of the Department's share of the required
21energy efficiency measures. The Agency shall implement a
22competitive procurement program to procure resources necessary
23to meet the standards specified in this Section, with the costs
24of these resources to be recovered in the same manner as
25provided for the Department in this Section.
26    (k) No electric utility shall be deemed to have failed to

 

 

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1meet the energy efficiency standards to the extent any such
2failure is due to a failure of the Department or the Agency.
3(Source: P.A. 95-481, eff. 8-28-07; 95-876, eff. 8-21-08;
496-33, eff. 7-10-09; 96-159, eff. 8-10-09; 96-1000, eff.
57-2-10.)
 
6    (220 ILCS 5/8-103A new)
7    Sec. 8-103A. Energy efficiency analysis. Beginning in
82013, an electric utility subject to the requirements of
9Section 8-103 of this Act shall include in its energy
10efficiency and demand-response plan submitted pursuant to
11subsection (f) of Section 8-103 an analysis of additional
12cost-effective energy efficiency measures that could be
13implemented, by customer class, absent the limitations set
14forth in subsection (d) of Section 8-103. In seeking public
15comment on the electric utility's plan pursuant to subsection
16(f) of Section 8-103, the Commission shall include, beginning
17in 2013, the assessment of additional cost-effective energy
18efficiency measures submitted pursuant to this Section. For
19purposes of this Section, the term "energy efficiency" shall
20have the meaning set forth in Section 1-10 of the Illinois
21Power Agency Act, and the term "cost-effective" shall have the
22meaning set forth in subsection (a) of Section 8-103 of this
23Act.
 
24    (220 ILCS 5/16-107.5)

 

 

SB1652 Enrolled- 58 -LRB097 09323 ASK 49458 b

1    Sec. 16-107.5. Net electricity metering.
2    (a) The Legislature finds and declares that a program to
3provide net electricity metering, as defined in this Section,
4for eligible customers can encourage private investment in
5renewable energy resources, stimulate economic growth, enhance
6the continued diversification of Illinois' energy resource
7mix, and protect the Illinois environment.
8    (b) As used in this Section, (i) "eligible customer" means
9a retail customer that owns or operates a solar, wind, or other
10eligible renewable electrical generating facility with a rated
11capacity of not more than 2,000 kilowatts that is located on
12the customer's premises and is intended primarily to offset the
13customer's own electrical requirements; (ii) "electricity
14provider" means an electric utility or alternative retail
15electric supplier; (iii) "eligible renewable electrical
16generating facility" means a generator powered by solar
17electric energy, wind, dedicated crops grown for electricity
18generation, agricultural residues, untreated and unadulterated
19wood waste, landscape trimmings, livestock manure, anaerobic
20digestion of livestock or food processing waste, fuel cells or
21microturbines powered by renewable fuels, or hydroelectric
22energy; and (iv) "net electricity metering" (or "net metering")
23means the measurement, during the billing period applicable to
24an eligible customer, of the net amount of electricity supplied
25by an electricity provider to the customer's premises or
26provided to the electricity provider by the customer.

 

 

SB1652 Enrolled- 59 -LRB097 09323 ASK 49458 b

1    (c) A net metering facility shall be equipped with metering
2equipment that can measure the flow of electricity in both
3directions at the same rate.
4        (1) For eligible residential customers whose electric
5    service has not been declared competitive pursuant to
6    Section 16-113 of this Act and whose electric delivery
7    service is provided and measured on a kilowatt-hour basis
8    and electric supply service is not provided based on hourly
9    pricing, this shall typically be accomplished through use
10    of a single, bi-directional meter. If the eligible
11    customer's existing electric revenue meter does not meet
12    this requirement, the electricity provider shall arrange
13    for the local electric utility or a meter service provider
14    to install and maintain a new revenue meter at the
15    electricity provider's expense.
16        (2) For eligible customers whose electric service has
17    not been declared competitive pursuant to Section 16-113 of
18    this Act and whose electric delivery service is provided
19    and measured on a kilowatt demand basis and electric supply
20    service is not provided based on hourly pricing, this shall
21    typically be accomplished through use of a dual channel
22    meter capable of measuring the flow of electricity both
23    into and out of the customer's facility at the same rate
24    and ratio. If such customer's existing electric revenue
25    meter does not meet this requirement, then the electricity
26    provider shall arrange for the local electric utility or a

 

 

SB1652 Enrolled- 60 -LRB097 09323 ASK 49458 b

1    meter service provider to install and maintain a new
2    revenue meter at the electricity provider's expense.
3        (3) For all other eligible customers, For
4    non-residential customers, the electricity provider may
5    arrange for the local electric utility or a meter service
6    provider to install and maintain metering equipment
7    capable of measuring the flow of electricity both into and
8    out of the customer's facility at the same rate and ratio,
9    typically through the use of a dual channel meter. If the
10    eligible customer's existing electric revenue meter does
11    not meet this requirement, then the costs of installing
12    such equipment shall be paid for by the customer. For
13    generators with a nameplate rating of 40 kilowatts and
14    below, the costs of installing such equipment shall be paid
15    for by the electricity provider. For generators with a
16    nameplate rating over 40 kilowatts and up to 2,000
17    kilowatts capacity, the costs of installing such equipment
18    shall be paid for by the customer. Any subsequent revenue
19    meter change necessitated by any eligible customer shall be
20    paid for by the customer.
21    (d) An electricity provider shall measure and charge or
22credit for the net electricity supplied to eligible customers
23or provided by eligible customers whose electric service has
24not been declared competitive pursuant to Section 16-113 of the
25Act and whose electric delivery service is provided and
26measured on a kilowatt-hour basis and electric supply service

 

 

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

 

 

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

 

 

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1    electricity provider shall continue to carry over any
2    excess kilowatt-hour credits earned and apply those
3    credits to subsequent billing periods to offset any
4    customer-generator consumption in those billing periods
5    until all credits are used or until the end of the
6    annualized period.
7        (3) At the end of the year or annualized over the
8    period that service is supplied by means of net metering,
9    or in the event that the retail customer terminates service
10    with the electricity provider prior to the end of the year
11    or the annualized period, any remaining credits in the
12    customer's account shall expire.
13    (e-5) An electricity provider shall provide electric
14service to eligible net metering customers whose electric
15service has not been declared competitive pursuant to Section
1616-113 of this Act and whose electric supply service is not
17provided based on hourly pricing who utilize net metering
18electric service at non-discriminatory rates that are
19identical, with respect to rate structure, retail rate
20components, and any monthly charges, to the rates that the
21customer would be charged if not a net metering customer. An
22electricity provider shall not charge net metering customers
23any fee or charge or require additional equipment, insurance,
24or any other requirements not specifically authorized by
25interconnection standards authorized by the Commission, unless
26the fee, charge, or other requirement would apply to other

 

 

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1similarly situated customers who are not net metering
2customers. The customer will remain responsible for all taxes,
3fees, and utility delivery charges that would otherwise be
4applicable to the net amount of electricity used by the
5customer. Subsections (c) through (e) of this Section shall not
6be construed to prevent an arms-length agreement between an
7electricity provider and an eligible customer that sets forth
8different prices, terms, and conditions for the provision of
9net metering service, including, but not limited to, the
10provision of the appropriate metering equipment for
11non-residential customers.
12    (f) Notwithstanding the requirements of subsections (c)
13through (e-5) (e) 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) nor (e) of this Section apply
18non-residential customers operating eligible renewable
19electrical generating facilities with a nameplate rating over
2040 kilowatts and up to 2,000 kilowatts. In such cases,
21electricity charges and credits shall be determined as follows:
22        (1) The electricity provider shall assess and the
23    customer remains responsible for all taxes, fees, and
24    utility delivery charges that would otherwise be
25    applicable to the gross amount of kilowatt-hours supplied
26    to the eligible customer by the electricity provider.

 

 

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

 

 

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

 

 

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1eligible customers until the load of its net metering customers
2equals 5% 1% of the total peak demand supplied by that
3electricity provider during the previous year. Electricity
4providers are authorized to offer net metering beyond the 5% 1%
5level if they so choose. The number of new eligible customers
6with generators that have a nameplate rating of 40 kilowatts
7and below will be limited to 200 total new billing accounts for
8the utilities (Ameren Companies, ComEd, and MidAmerican) for
9the period of April 1, 2008 through March 31, 2009.
10    (k) Each electricity provider shall maintain records and
11report annually to the Commission the total number of net
12metering customers served by the provider, as well as the type,
13capacity, and energy sources of the generating systems used by
14the net metering customers. Nothing in this Section shall limit
15the ability of an electricity provider to request the redaction
16of information deemed by the Commission to be confidential
17business information. Each electricity provider shall notify
18the Commission when the total generating capacity of its net
19metering customers is equal to or in excess of the 5% 1% cap
20specified in subsection (j) of this Section.
21    (l) Notwithstanding the definition of "eligible customer"
22in item (i) of subsection (b) of this Section, each electricity
23provider shall consider whether to allow meter aggregation for
24the purposes of net metering on:
25        (1) properties owned or leased by multiple customers
26    that contribute to the operation of an eligible renewable

 

 

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1    electrical generating facility, such as a community-owned
2    wind project, a community-owned biomass project, a
3    community-owned solar project, or a community methane
4    digester processing livestock waste from multiple sources;
5    and
6        (2) individual units, apartments, or properties owned
7    or leased by multiple customers and collectively served by
8    a common eligible renewable electrical generating
9    facility, such as an apartment building served by
10    photovoltaic panels on the roof.
11    For the purposes of this subsection (l), "meter
12aggregation" means the combination of reading and billing on a
13pro rata basis for the types of eligible customers described in
14this Section.
15    (m) Nothing in this Section shall affect the right of an
16electricity provider to continue to provide, or the right of a
17retail customer to continue to receive service pursuant to a
18contract for electric service between the electricity provider
19and the retail customer in accordance with the prices, terms,
20and conditions provided for in that contract. Either the
21electricity provider or the customer may require compliance
22with the prices, terms, and conditions of the contract.
23(Source: P.A. 95-420, eff. 8-24-07.)
 
24    (220 ILCS 5/16-108.5 new)
25    Sec. 16-108.5. Infrastructure investment and

 

 

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1modernization; regulatory reform.
2    (a) The General Assembly recognizes that for well over a
3century Illinois residents and businesses have been
4well-served by and have benefitted from a comprehensive
5electric utility system. The General Assembly finds that
6electric utilities are now entering a new construction cycle
7that is needed to refurbish, rebuild, modernize, and expand
8systems to continue to provide safe, reliable, and affordable
9service to the State's current and future utility customers in
10this newly digitized age. In particular, the General Assembly
11finds that it is the policy of this State that significant
12investments must be made in the State's electric grid over the
13next decade to modernize and upgrade transmission and
14distribution facilities in the State. These investments will
15ensure that the State's electric utility infrastructure will
16promote future economic development in the State and that the
17State's electric utilities will be able to continue to provide
18quality electric service to their customers, including
19innovative technological offerings that will enhance customer
20experience and choice such as smart meters that are dependent
21on a modernized or Smart Grid. These investments, including
22programs to reinforce the safety and security of high voltage
23transmission lines, will also ensure that the State's electric
24utility infrastructure continues to be safe and reliable. The
25introduction of performance metrics will further ensure that
26reliability and other indicators are not just maintained but

 

 

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1improved over the next decade.
2    The General Assembly further recognizes that, in addition
3to attracting capital and businesses to the State, these
4investments will create training opportunities for the
5citizens of this State, all of which will create new employment
6opportunities for Illinoisans at a time when they are most
7needed, especially for minority-owned and female-owned
8business enterprises. The General Assembly further finds that
9regulatory reform measures that increase predictability,
10stability, and transparency in the ratemaking process are
11needed to promote prudent, long-term infrastructure investment
12and to mutually benefit the State's electric utilities and
13their customers, regulators, and investors.
14    (b) For purposes of this Section, "participating utility"
15means an electric utility or a combination utility serving more
16than 1,000,000 customers in Illinois that voluntarily elects
17and commits to undertake the infrastructure investment program
18consisting of the commitments and obligations described in this
19subsection (b), notwithstanding any other provisions of this
20Act and without obtaining any approvals from the Commission or
21any other agency other than as set forth in this Section,
22regardless of whether any such approval would otherwise be
23required. "Combination utility" means a utility that, as of
24January 1, 2011, provided electric service to at least one
25million retail customers in Illinois and gas service to at
26least 500,000 retail customers in Illinois. A participating

 

 

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1utility shall recover the expenditures made under the
2infrastructure investment program through the ratemaking
3process, including, but not limited to, the performance-based
4formula rate and process set forth in this Section.
5    During the infrastructure investment program's peak
6program year, a participating utility other than a combination
7utility shall create 2,000 full-time equivalent jobs in
8Illinois, and a participating utility that is a combination
9utility shall create 450 full-time equivalent jobs in Illinois
10related to the provision of electric service, including direct
11jobs, contractor positions, and induced jobs. For purposes of
12this Section, "peak program year" means the consecutive
1312-month period with the highest number of full-time equivalent
14jobs that occurs between the beginning of investment year 2 and
15the end of investment year 4.
16    A participating utility shall meet one of the following
17commitments, as applicable:
18        (1) Beginning no later than 180 days after a
19    participating utility other than a combination utility
20    files a performance-based formula rate tariff pursuant to
21    subsection (c) of this Section, or, beginning no later than
22    January 1, 2012 if such utility files such
23    performance-based formula rate tariff within 14 days of the
24    effective date of this amendatory Act of the 97th General
25    Assembly, the participating utility shall, except as
26    provided in subsection (b-5):

 

 

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1            (A) over a 5-year period, invest an estimated
2        $1,100,000,000 in electric system upgrades,
3        modernization projects, and training facilities,
4        including, but not limited to:
5                (i) distribution infrastructure improvements
6            totaling an estimated $1,000,000,000, including
7            underground residential distribution cable
8            injection and replacement and mainline cable
9            system refurbishment and replacement projects;
10                (ii) training facility construction or upgrade
11            projects totaling an estimated $10,000,000,
12            provided that, at a minimum, one such facility
13            shall be located in a municipality having a
14            population of more than 2 million residents and one
15            such facility shall be located in a municipality
16            having a population of more than 150,000 residents
17            but fewer than 170,000 residents; any such new
18            facility located in a municipality having a
19            population of more than 2 million residents must be
20            designed for the purpose of obtaining, and the
21            owner of the facility shall apply for,
22            certification under the United States Green
23            Building Council's Leadership in Energy Efficiency
24            Design Green Building Rating System; and
25                (iii) wood pole inspection, treatment, and
26            replacement programs; and

 

 

SB1652 Enrolled- 73 -LRB097 09323 ASK 49458 b

1            (B) over a 10-year period, invest an estimated
2        $1,500,000,000 to upgrade and modernize its
3        transmission and distribution infrastructure and in
4        Smart Grid electric system upgrades, including, but
5        not limited to:
6                (i) additional smart meters;
7                (ii) distribution automation;
8                (iii) associated cyber secure data
9            communication network; and
10                (iv) substation micro-processor relay
11            upgrades.
12        (2) Beginning no later than 180 days after a
13    participating utility that is a combination utility files a
14    performance-based formula rate tariff pursuant to
15    subsection (c) of this Section, or, beginning no later than
16    January 1, 2012 if such utility files such
17    performance-based formula rate tariff within 14 days of the
18    effective date of this amendatory Act of the 97th General
19    Assembly, the participating utility shall, except as
20    provided in subsection (b-5):
21            (A) over a 10-year period, invest an estimated
22        $265,000,000 in electric system upgrades,
23        modernization projects, and training facilities,
24        including, but not limited to:
25                (i) distribution infrastructure improvements
26            totaling an estimated $245,000,000, which may

 

 

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1            include bulk supply substations, transformers,
2            reconductoring, and rebuilding overhead
3            distribution and sub-transmission lines,
4            underground residential distribution cable
5            injection and replacement and mainline cable
6            system refurbishment and replacement projects;
7                (ii) training facility construction or upgrade
8            projects totaling an estimated $1,000,000; any
9            such new facility must be designed for the purpose
10            of obtaining, and the owner of the facility shall
11            apply for, certification under the United States
12            Green Building Council's Leadership in Energy
13            Efficiency Design Green Building Rating System;
14            and
15                (iii) wood pole inspection, treatment, and
16            replacement programs; and
17            (B) over a 10-year period, invest an estimated
18        $360,000,000 to upgrade and modernize its transmission
19        and distribution infrastructure and in Smart Grid
20        electric system upgrades, including, but not limited
21        to:
22                (i) additional smart meters;
23                (ii) distribution automation;
24                (iii) associated cyber secure data
25            communication network; and
26                (iv) substation micro-processor relay

 

 

SB1652 Enrolled- 75 -LRB097 09323 ASK 49458 b

1            upgrades.
2    For purposes of this Section, "Smart Grid electric system
3upgrades" shall have the meaning set forth in subsection (a) of
4Section 16-108.6 of this Act.
5    The investments in the infrastructure investment program
6described in this subsection (b) shall be incremental to the
7participating utility's annual capital investment program, as
8defined by, for purposes of this subsection (b), the
9participating utility's average capital spend for calendar
10years 2008, 2009, and 2010 as reported in the applicable
11Federal Energy Regulatory Commission (FERC) Form 1; provided
12that where one or more utilities have merged, the average
13capital spend shall be determined using the aggregate of the
14merged utilities' capital spend reported in FERC Form 1 for the
15years 2008, 2009, and 2010.
16    Within 60 days after filing a tariff under subsection (c)
17of this Section, a participating utility shall submit to the
18Commission its plan, including scope, schedule, and staffing,
19for satisfying its infrastructure investment program
20commitments pursuant to this subsection (b). The submitted plan
21shall include a schedule and staffing plan for the next
22calendar year. The plan shall also include a plan for the
23creation, operation, and administration of a Smart Grid test
24bed as described in subsection (c) of Section 16-108.8. The
25plan need not allocate the work equally over the respective
26periods, but should allocate material increments throughout

 

 

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1such periods commensurate with the work to be undertaken. No
2later than April 1 of each subsequent year, the utility shall
3submit to the Commission a report that includes any updates to
4the plan, a schedule for the next calendar year, the
5expenditures made for the prior calendar year and cumulatively,
6and the number of full-time equivalent jobs created for the
7prior calendar year and cumulatively. If the utility is
8materially deficient in satisfying a schedule or staffing plan,
9then the report must also include a corrective action plan to
10address the deficiency. The fact that the plan, implementation
11of the plan, or a schedule changes shall not imply the
12imprudence or unreasonableness of the infrastructure
13investment program, plan, or schedule.
14    With respect to the participating utility's peak job
15commitment, if, after considering the utility's corrective
16action plan and compliance thereunder, the Commission enters an
17order finding, after notice and hearing, that a participating
18utility did not satisfy its peak job commitment described in
19this subsection (b) for reasons that are reasonably within its
20control, then the Commission shall also determine, after
21consideration of the evidence, including, but not limited to,
22evidence submitted by the Department of Commerce and Economic
23Opportunity and the utility, the deficiency in the number of
24full-time equivalent jobs during the peak program year due to
25such failure. The Commission shall notify the Department of any
26proceeding that is initiated pursuant to this paragraph. For

 

 

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1each full-time equivalent job deficiency during the peak
2program year that the Commission finds as set forth in this
3paragraph, the participating utility shall, within 30 days
4after the entry of the Commission's order, pay $3,000 to a fund
5for training grants administered under Section 605-800 of The
6Department of Commerce and Economic Opportunity Law, which
7shall not be a recoverable expense.
8    With respect to the participating utility's investment
9amount commitments, if, after considering the utility's
10corrective action plan and compliance thereunder, the
11Commission enters an order finding, after notice and hearing,
12that a participating utility is not satisfying its investment
13amount commitments described in this subsection (b), then the
14utility shall no longer be eligible to annually update the
15performance-based formula rate tariff pursuant to subsection
16(d) of this Section. In such event, the then current rates
17shall remain in effect until such time as new rates are set
18pursuant to Article IX of this Act, subject to retroactive
19adjustment, with interest, to reconcile rates charged with
20actual costs.
21    If the Commission finds that a participating utility is no
22longer eligible to update the performance-based formula rate
23tariff pursuant to subsection (d) of this Section, or the
24performance-based formula rate is otherwise terminated, then
25the participating utility's voluntary commitments and
26obligations under this subsection (b) shall immediately

 

 

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1terminate, except for the utility's obligation to pay an amount
2already owed to the fund for training grants pursuant to a
3Commission order.
4    In meeting the obligations of this subsection (b), to the
5extent feasible and consistent with State and federal law, the
6investments under the infrastructure investment program should
7provide employment opportunities for all segments of the
8population and workforce, including minority-owned and
9female-owned business enterprises, and shall not, consistent
10with State and federal law, discriminate based on race or
11socioeconomic status.
12    (b-5) Nothing in this Section shall prohibit the Commission
13from investigating the prudence and reasonableness of the
14expenditures made under the infrastructure investment program
15during the annual review required by subsection (d) of this
16Section and shall, as part of such investigation, determine
17whether the utility's actual costs under the program are
18prudent and reasonable. The fact that a participating utility
19invests more than the minimum amounts specified in subsection
20(b) of this Section or its plan shall not imply imprudence or
21unreasonableness.
22    If the participating utility finds that it is implementing
23its plan for satisfying the infrastructure investment program
24commitments described in subsection (b) of this Section at a
25cost below the estimated amounts specified in subsection (b) of
26this Section, then the utility may file a petition with the

 

 

SB1652 Enrolled- 79 -LRB097 09323 ASK 49458 b

1Commission requesting that it be permitted to satisfy its
2commitments by spending less than the estimated amounts
3specified in subsection (b) of this Section. The Commission
4shall, after notice and hearing, enter its order approving, or
5approving as modified, or denying each such petition within 150
6days after the filing of the petition.
7    In no event, absent General Assembly approval, shall the
8capital investment costs incurred by a participating utility
9other than a combination utility in satisfying its
10infrastructure investment program commitments described in
11subsection (b) of this Section exceed $3,000,000,000 or, for a
12participating utility that is a combination utility,
13$720,000,000. If the participating utility's updated cost
14estimates for satisfying its infrastructure investment program
15commitments described in subsection (b) of this Section exceed
16the limitation imposed by this subsection (b-5), then it shall
17submit a report to the Commission that identifies the increased
18costs and explains the reason or reasons for the increased
19costs no later than the year in which the utility estimates it
20will exceed the limitation. The Commission shall review the
21report and shall, within 90 days after the participating
22utility files the report, report to the General Assembly its
23findings regarding the participating utility's report. If the
24General Assembly does not amend the limitation imposed by this
25subsection (b-5), then the utility may modify its plan so as
26not to exceed the limitation imposed by this subsection (b-5)

 

 

SB1652 Enrolled- 80 -LRB097 09323 ASK 49458 b

1and may propose corresponding changes to the metrics
2established pursuant to subparagraphs (5) through (8) of
3subsection (f) of this Section, and the Commission may modify
4the metrics and incremental savings goals established pursuant
5to subsection (f) of this Section accordingly.
6    (c) A participating utility may elect to recover its
7delivery services costs through a performance-based formula
8rate approved by the Commission, which shall specify the cost
9components that form the basis of the rate charged to customers
10with sufficient specificity to operate in a standardized manner
11and be updated annually with transparent information that
12reflects the utility's actual costs to be recovered during the
13applicable rate year, which is the period beginning with the
14first billing day of January and extending through the last
15billing day of the following December. In the event the utility
16recovers a portion of its costs through automatic adjustment
17clause tariffs on the effective date of this amendatory Act of
18the 97th General Assembly, the utility may elect to continue to
19recover these costs through such tariffs, but then these costs
20shall not be recovered through the performance-based formula
21rate.
22    The performance-based formula rate shall be implemented
23through a tariff filed with the Commission consistent with the
24provisions of this subsection (c) that shall be applicable to
25all delivery services customers. The Commission shall initiate
26and conduct an investigation of the tariff in a manner

 

 

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1consistent with the provisions of this subsection (c) and the
2provisions of Article IX of this Act to the extent they do not
3conflict with this subsection (c). Except in the case where the
4Commission finds, after notice and hearing, that a
5participating utility is not satisfying its investment amount
6commitments under subsection (b) of this Section, the
7performance-based formula rate shall remain in effect at the
8discretion of the utility. The performance-based formula rate
9approved by the Commission shall do the following:
10        (1) Provide for the recovery of the utility's actual
11    costs of delivery services that are prudently incurred and
12    reasonable in amount consistent with Commission practice
13    and law. The sole fact that a cost differs from that
14    incurred in a prior calendar year or that an investment is
15    different from that made in a prior calendar year shall not
16    imply the imprudence or unreasonableness of that cost or
17    investment.
18        (2) Reflect the utility's actual capital structure for
19    the applicable calendar year, excluding goodwill, subject
20    to a determination of prudence and reasonableness
21    consistent with Commission practice and law.
22        (3) Include a cost of equity, which shall be calculated
23    as the sum of the following:
24            (A) the average for the applicable calendar year of
25        the monthly average yields of 30-year U.S. Treasury
26        bonds published by the Board of Governors of the

 

 

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1        Federal Reserve System in its weekly H.15 Statistical
2        Release or successor publication; and
3            (B) 600 basis points.
4        At such time as the Board of Governors of the Federal
5    Reserve System ceases to include the monthly average yields
6    of 30-year U.S. Treasury bonds in its weekly H.15
7    Statistical Release or successor publication, the monthly
8    average yields of the U.S. Treasury bonds then having the
9    longest duration published by the Board of Governors in its
10    weekly H.15 Statistical Release or successor publication
11    shall instead be used for purposes of this paragraph (3).
12        (4) Permit and set forth protocols, subject to a
13    determination of prudence and reasonableness consistent
14    with Commission practice and law, for the following:
15            (A) recovery of incentive compensation expense
16        that is based on the achievement of operational
17        metrics, including metrics related to budget controls,
18        outage duration and frequency, safety, customer
19        service, efficiency and productivity, and
20        environmental compliance. Incentive compensation
21        expense that is based on net income or an affiliate's
22        earnings per share shall not be recoverable under the
23        performance-based formula rate;
24            (B) recovery of pension and other post-employment
25        benefits expense, provided that such costs are
26        supported by an actuarial study;

 

 

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1            (C) recovery of severance costs, provided that if
2        the amount is over $3,700,000 for a participating
3        utility that is a combination utility or $10,000,000
4        for a participating utility that serves more than 3
5        million retail customers, then the full amount shall be
6        amortized consistent with subparagraph (F) of this
7        paragraph (4);
8            (D) investment return on pension assets net of
9        deferred tax benefits equal to the utility's long-term
10        debt cost of capital as of the end of the applicable
11        calendar year;
12            (E) recovery of the expenses related to the
13        Commission proceeding under this subsection (c) to
14        approve this performance-based formula rate and
15        initial rates or to subsequent proceedings related to
16        the formula, provided that the recovery shall be
17        amortized over a 3-year period; recovery of expenses
18        related to the annual Commission proceedings under
19        subsection (d) of this Section to review the inputs to
20        the performance-based formula rate shall be expensed
21        and recovered through the performance-based formula
22        rate;
23            (F) amortization over a 5-year period of the full
24        amount of each charge or credit that exceeds $3,700,000
25        for a participating utility that is a combination
26        utility or $10,000,000 for a participating utility

 

 

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1        that serves more than 3 million retail customers in the
2        applicable calendar year and that relates to a
3        workforce reduction program's severance costs, changes
4        in accounting rules, changes in law, compliance with
5        any Commission-initiated audit, or a single storm or
6        other similar expense, provided that any unamortized
7        balance shall be reflected in rate base. For purposes
8        of this subparagraph (F), changes in law includes any
9        enactment, repeal, or amendment in a law, ordinance,
10        rule, regulation, interpretation, permit, license,
11        consent, or order, including those relating to taxes,
12        accounting, or to environmental matters, or in the
13        interpretation or application thereof by any
14        governmental authority occurring after the effective
15        date of this amendatory Act of the 97th General
16        Assembly;
17            (G) recovery of existing regulatory assets over
18        the periods previously authorized by the Commission;
19            (H) historical weather normalized billing
20        determinants; and
21            (I) allocation methods for common costs.
22        (5) Provide that if the participating utility's earned
23    rate of return on common equity related to the provision of
24    delivery services for the prior rate year (calculated using
25    costs and capital structure approved by the Commission as
26    provided in subparagraph (2) of this subsection (c),

 

 

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1    consistent with this Section, in accordance with
2    Commission rules and orders, including, but not limited to,
3    adjustments for goodwill, and after any Commission-ordered
4    disallowances and taxes) is more than 50 basis points
5    higher than the rate of return on common equity calculated
6    pursuant to paragraph (3) of this subsection (c) (after
7    adjusting for any penalties to the rate of return on common
8    equity applied pursuant to the performance metrics
9    provision of subsection (f) of this Section), then the
10    participating utility shall apply a credit through the
11    performance-based formula rate that reflects an amount
12    equal to the value of that portion of the earned rate of
13    return on common equity that is more than 50 basis points
14    higher than the rate of return on common equity calculated
15    pursuant to paragraph (3) of this subsection (c) (after
16    adjusting for any penalties to the rate of return on common
17    equity applied pursuant to the performance metrics
18    provision of subsection (f) of this Section) for the prior
19    rate year, adjusted for taxes. If the participating
20    utility's earned rate of return on common equity related to
21    the provision of delivery services for the prior rate year
22    (calculated using costs and capital structure approved by
23    the Commission as provided in subparagraph (2) of this
24    subsection (c), consistent with this Section, in
25    accordance with Commission rules and orders, including,
26    but not limited to, adjustments for goodwill, and after any

 

 

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1    Commission-ordered disallowances and taxes) is more than
2    50 basis points less than the return on common equity
3    calculated pursuant to paragraph (3) of this subsection (c)
4    (after adjusting for any penalties to the rate of return on
5    common equity applied pursuant to the performance metrics
6    provision of subsection (f) of this Section), then the
7    participating utility shall apply a charge through the
8    performance-based formula rate that reflects an amount
9    equal to the value of that portion of the earned rate of
10    return on common equity that is more than 50 basis points
11    less than the rate of return on common equity calculated
12    pursuant to paragraph (3) of this subsection (c) (after
13    adjusting for any penalties to the rate of return on common
14    equity applied pursuant to the performance metrics
15    provision of subsection (f) of this Section) for the prior
16    rate year, adjusted for taxes.
17        (6) Provide for an annual reconciliation, with
18    interest as described in subsection (d) of this Section, of
19    the revenue requirement reflected in rates for each
20    calendar year, beginning with the calendar year in which
21    the utility files its performance-based formula rate
22    tariff pursuant to subsection (c) of this Section, with
23    what the revenue requirement would have been had the actual
24    cost information for the applicable calendar year been
25    available at the filing date.
26    The utility shall file, together with its tariff, final

 

 

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1data based on its most recently filed FERC Form 1, plus
2projected plant additions and correspondingly updated
3depreciation reserve and expense for the calendar year in which
4the tariff and data are filed, that shall populate the
5performance-based formula rate and set the initial delivery
6services rates under the formula. For purposes of this Section,
7"FERC Form 1" means the Annual Report of Major Electric
8Utilities, Licensees and Others that electric utilities are
9required to file with the Federal Energy Regulatory Commission
10under the Federal Power Act, Sections 3, 4(a), 304 and 209,
11modified as necessary to be consistent with 83 Ill. Admin. Code
12Part 415 as of May 1, 2011. Nothing in this Section is intended
13to allow costs that are not otherwise recoverable to be
14recoverable by virtue of inclusion in FERC Form 1.
15    After the utility files its proposed performance-based
16formula rate structure and protocols and initial rates, the
17Commission shall initiate a docket to review the filing. The
18Commission shall enter an order approving, or approving as
19modified, the performance-based formula rate, including the
20initial rates, as just and reasonable within 270 days after the
21date on which the tariff was filed, or, if the tariff is filed
22within 14 days after the effective date of this amendatory Act
23of the 97th General Assembly, then by May 31, 2012. Such review
24shall be based on the same evidentiary standards, including,
25but not limited to, those concerning the prudence and
26reasonableness of the costs incurred by the utility, the

 

 

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1Commission applies in a hearing to review a filing for a
2general increase in rates under Article IX of this Act. The
3initial rates shall take effect within 30 days after the
4Commission's order approving the performance-based formula
5rate tariff.
6    Until such time as the Commission approves a different rate
7design and cost allocation pursuant to subsection (e) of this
8Section, rate design and cost allocation across customer
9classes shall be consistent with the Commission's most recent
10order regarding the participating utility's request for a
11general increase in its delivery services rates.
12    Subsequent changes to the performance-based formula rate
13structure or protocols shall be made as set forth in Section
149-201 of this Act, but nothing in this subsection (c) is
15intended to limit the Commission's authority under Article IX
16and other provisions of this Act to initiate an investigation
17of a participating utility's performance-based formula rate
18tariff, provided that any such changes shall be consistent with
19paragraphs (1) through (6) of this subsection (c). Any change
20ordered by the Commission shall be made at the same time new
21rates take effect following the Commission's next order
22pursuant to subsection (d) of this Section, provided that the
23new rates take effect no less than 30 days after the date on
24which the Commission issues an order adopting the change.
25    A participating utility that files a tariff pursuant to
26this subsection (c) must submit a one-time $200,000 filing fee

 

 

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1at the time the Chief Clerk of the Commission accepts the
2filing, which shall be a recoverable expense.
3    In the event the performance-based formula rate is
4terminated, the then current rates shall remain in effect until
5such time as new rates are set pursuant to Article IX of this
6Act, subject to retroactive rate adjustment, with interest, to
7reconcile rates charged with actual costs. At such time that
8the performance-based formula rate is terminated, the
9participating utility's voluntary commitments and obligations
10under subsection (b) of this Section shall immediately
11terminate, except for the utility's obligation to pay an amount
12already owed to the fund for training grants pursuant to a
13Commission order issued under subsection (b) of this Section.
14    (d) Subsequent to the Commission's issuance of an order
15approving the utility's performance-based formula rate
16structure and protocols, and initial rates under subsection (c)
17of this Section, the utility shall file, on or before May 1 of
18each year, with the Chief Clerk of the Commission its updated
19cost inputs to the performance-based formula rate for the
20applicable rate year and the corresponding new charges. Each
21such filing shall conform to the following requirements and
22include the following information:
23        (1) The inputs to the performance-based formula rate
24    for the applicable rate year shall be based on final
25    historical data reflected in the utility's most recently
26    filed annual FERC Form 1 plus projected plant additions and

 

 

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1    correspondingly updated depreciation reserve and expense
2    for the calendar year in which the inputs are filed. The
3    filing shall also include a reconciliation of the revenue
4    requirement that was in effect for the prior rate year (as
5    set by the cost inputs for the prior rate year) with the
6    actual revenue requirement for the prior rate year (as
7    reflected in the applicable FERC Form 1 that reports the
8    actual costs for the prior rate year). Any over-collection
9    or under-collection indicated by such reconciliation shall
10    be reflected as a credit against, or recovered as an
11    additional charge to, respectively, with interest, the
12    charges for the applicable rate year. Provided, however,
13    that the first such reconciliation shall be for the
14    calendar year in which the utility files its
15    performance-based formula rate tariff pursuant to
16    subsection (c) of this Section and shall reconcile (i) the
17    revenue requirement or requirements established by the
18    rate order or orders in effect from time to time during
19    such calendar year (weighted, as applicable) with (ii) the
20    revenue requirement for that calendar year calculated
21    pursuant to the performance-based formula rate using (A)
22    actual costs for that year as reflected in the applicable
23    FERC Form 1, and (B) for the first such reconciliation
24    only, the cost of equity approved by the Commission in such
25    order or orders in effect during that year (weighted, as
26    applicable). The first such reconciliation is not intended

 

 

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1    to provide for the recovery of costs previously excluded
2    from rates based on a prior Commission order finding of
3    imprudence or unreasonableness. Each reconciliation shall
4    be certified by the participating utility in the same
5    manner that FERC Form 1 is certified. The filing shall also
6    include the charge or credit, if any, resulting from the
7    calculation required by paragraph (6) of subsection (c) of
8    this Section.
9        Notwithstanding anything that may be to the contrary,
10    the intent of the reconciliation is to ultimately reconcile
11    the revenue requirement reflected in rates for each
12    calendar year, beginning with the calendar year in which
13    the utility files its performance-based formula rate
14    tariff pursuant to subsection (c) of this Section, with
15    what the revenue requirement would have been had the actual
16    cost information for the applicable calendar year been
17    available at the filing date.
18        (2) The new charges shall take effect beginning on the
19    first billing day of the following January billing period
20    and remain in effect through the last billing day of the
21    next December billing period regardless of whether the
22    Commission enters upon a hearing pursuant to this
23    subsection (d).
24        (3) The filing shall include relevant and necessary
25    data and documentation for the applicable rate year that is
26    consistent with the Commission's rules applicable to a

 

 

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1    filing for a general increase in rates or any rules adopted
2    by the Commission to implement this Section. Normalization
3    adjustments shall not be required. Notwithstanding any
4    other provision of this Section or Act or any rule or other
5    requirement adopted by the Commission, a participating
6    utility that is a combination utility with more than one
7    rate zone shall not be required to file a separate set of
8    such data and documentation for each rate zone and may
9    combine such data and documentation into a single set of
10    schedules.
11    Within 45 days after the utility files its annual update of
12cost inputs to the performance-based formula rate, the
13Commission shall have the authority, either upon complaint or
14its own initiative, but with reasonable notice, to enter upon a
15hearing concerning the prudence and reasonableness of the costs
16incurred by the utility to be recovered during the applicable
17rate year that are reflected in the inputs to the
18performance-based formula rate derived from the utility's FERC
19Form 1. During the course of the hearing, each objection shall
20be stated with particularity and evidence provided in support
21thereof, after which the utility shall have the opportunity to
22rebut the evidence. Discovery shall be allowed consistent with
23the Commission's Rules of Practice, which Rules shall be
24enforced by the Commission or the assigned hearing examiner.
25The Commission shall apply the same evidentiary standards,
26including, but not limited to, those concerning the prudence

 

 

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1and reasonableness of the costs incurred by the utility, in the
2hearing as it would apply in a hearing to review a filing for a
3general increase in rates under Article IX of this Act. The
4Commission shall not, however, have the authority in a
5proceeding under this subsection (d) to consider or order any
6changes to the structure or protocols of the performance-based
7formula rate approved pursuant to subsection (c) of this
8Section. In a proceeding under this subsection (d), the
9Commission shall enter its order no later than the earlier of
10240 days after the utility's filing of its annual update of
11cost inputs to the performance-based formula rate or December
1231. The Commission's determinations of the prudence and
13reasonableness of the costs incurred for the applicable
14calendar year shall be final upon entry of the Commission's
15order and shall not be subject to reopening, reexamination, or
16collateral attack in any other Commission proceeding, case,
17docket, order, rule or regulation, provided, however, that
18nothing in this subsection (d) shall prohibit a party from
19petitioning the Commission to rehear or appeal to the courts
20the order pursuant to the provisions of this Act.
21    In the event the Commission does not, either upon complaint
22or its own initiative, enter upon a hearing within 45 days
23after the utility files the annual update of cost inputs to its
24performance-based formula rate, then the costs incurred for the
25applicable calendar year shall be deemed prudent and
26reasonable, and the filed charges shall not be subject to

 

 

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1reopening, reexamination, or collateral attack in any other
2proceeding, case, docket, order, rule, or regulation.
3    A participating utility's first filing of the updated cost
4inputs, and any Commission investigation of such inputs
5pursuant to this subsection (d) shall proceed notwithstanding
6the fact that the Commission's investigation under subsection
7(c) of this Section is still pending and notwithstanding any
8other law, order, rule, or Commission practice to the contrary.
9    (e) Nothing in subsections (c) or (d) of this Section shall
10prohibit the Commission from investigating, or a participating
11utility from filing, revenue-neutral tariff changes related to
12rate design of a performance-based formula rate that has been
13placed into effect for the utility. Following approval of a
14participating utility's performance-based formula rate tariff
15pursuant to subsection (c) of this Section, the utility shall
16make a filing with the Commission within one year after the
17effective date of the performance-based formula rate tariff
18that proposes changes to the tariff to incorporate the findings
19of any final rate design orders of the Commission applicable to
20the participating utility and entered subsequent to the
21Commission's approval of the tariff. The Commission shall,
22after notice and hearing, enter its order approving, or
23approving with modification, the proposed changes to the
24performance-based formula rate tariff within 240 days after the
25utility's filing. Following such approval, the utility shall
26make a filing with the Commission during each subsequent 3-year

 

 

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1period that either proposes revenue-neutral tariff changes or
2re-files the existing tariffs without change, which shall
3present the Commission with an opportunity to suspend the
4tariffs and consider revenue-neutral tariff changes related to
5rate design.
6    (f) Within 30 days after the filing of a tariff pursuant to
7subsection (c) of this Section, each participating utility
8shall develop and file with the Commission multi-year metrics
9designed to achieve, ratably over a 10-year period, improvement
10over baseline performance values as follows:
11        (1) Twenty percent improvement in the System Average
12    Interruption Frequency Index, using a baseline of the
13    average of the data from 2001 through 2010.
14        (2) Fifteen percent improvement in the system Customer
15    Average Interruption Duration Index, using a baseline of
16    the average of the data from 2001 through 2010.
17        (3) For a participating utility other than a
18    combination utility, 20% improvement in the System Average
19    Interruption Frequency Index for its Southern Region,
20    using a baseline of the average of the data from 2001
21    through 2010. For purposes of this paragraph (C), Southern
22    Region shall have the meaning set forth in the
23    participating utility's most recent report filed pursuant
24    to Section 16-125 of this Act.
25        (4) Seventy-five percent improvement in the total
26    number of customers who exceed the service reliability

 

 

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1    targets as set forth in subparagraphs (A) through (C) of
2    paragraph (4) of subsection (b) of 83 Ill. Admin. Code Part
3    411.140 as of May 1, 2011, using 2010 as the baseline year.
4        (5) Reduction in issuance of estimated electric bills:
5    90% improvement for a participating utility other than a
6    combination utility, and 56% improvement for a
7    participating utility that is a combination utility, using
8    a baseline of the average number of estimated bills for the
9    years 2008 through 2010.
10        (6) Consumption on inactive meters: 90% improvement
11    for a participating utility other than a combination
12    utility, and 56% improvement for a participating utility
13    that is a combination utility, using a baseline of the
14    average unbilled kilowatthours for the years 2009 and 2010.
15        (7) Unaccounted for energy: 50% improvement for a
16    participating utility other than a combination utility
17    using a baseline of the non-technical line loss unaccounted
18    for energy kilowatthours for the year 2009.
19        (8) Uncollectible expense: reduce uncollectible
20    expense by at least $30,000,000 for a participating utility
21    other than a combination utility and by at least $3,500,000
22    for a participating utility that is a combination utility,
23    using a baseline of the average uncollectible expense for
24    the years 2008 through 2010.
25        (9) Opportunities for minority-owned and female-owned
26    business enterprises: design a performance metric

 

 

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1    regarding the creation of opportunities for minority-owned
2    and female-owned business enterprises consistent with
3    State and federal law using a base performance value of the
4    percentage of the participating utility's capital
5    expenditures that were paid to minority-owned and
6    female-owned business enterprises in 2010.
7    The definitions set forth in 83 Ill. Admin. Code Part
8411.20 as of May 1, 2011 shall be used for purposes of
9calculating performance under paragraphs (1) through (3) of
10this subsection (f), provided, however, that the participating
11utility may exclude up to 9 extreme weather event days from
12such calculation for each year. For purposes of this Section,
13an extreme weather event day is a 24-hour calendar day
14(beginning at 12:00 a.m. and ending at 11:59 p.m.) during which
15any weather event (e.g., storm, tornado) caused interruptions
16for 10,000 or more of the participating utility's customers for
173 hours or more. If there are more than 9 extreme weather event
18days in a year, then the utility may choose no more than 9
19extreme weather event days to exclude, provided that the same
20extreme weather event days are excluded from each of the
21calculations performed under paragraphs (1) through (3) of this
22subsection (f).
23    The metrics shall include incremental performance goals
24for each year of the 10-year period, which shall be designed to
25demonstrate that the utility is on track to achieve the
26performance goal in each category at the end of the 10-year

 

 

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1period. The utility shall elect when the 10-year period shall
2commence, provided that it begins no later than 14 months
3following the date on which the utility begins investing
4pursuant to subsection (b) of this Section.
5    The metrics and performance goals set forth in
6subparagraphs (5) through (8) of this subsection (f) are based
7on the assumptions that the participating utility may fully
8implement the technology described in subsection (b) of this
9Section, including utilizing the full functionality of such
10technology and that there is no requirement for personal
11on-site notification. If the utility is unable to meet the
12metrics and performance goals set forth in subparagraphs (5)
13through (8) of this subsection (f) for such reasons, and the
14Commission so finds after notice and hearing, then the utility
15shall be excused from compliance, but only to the limited
16extent achievement of the affected metrics and performance
17goals was hindered by the less than full implementation.
18    (f-5) The financial penalties applicable to the metrics
19described in subparagraphs (1) through (8) of subsection (f) of
20this Section, as applicable, shall be applied through an
21adjustment to the participating utility's return on equity as
22follows:
23        (1) With respect to each of the incremental annual
24    performance goals established pursuant to paragraph (1) of
25    subsection (f) of this Section, for each year that a
26    participating utility other than a combination utility

 

 

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1    does not achieve the annual goal, the participating
2    utility's return on equity shall be reduced by 5 basis
3    points for such unachieved goal for the following 12-month
4    period, and for each year that a participating utility that
5    is a combination utility does not achieve the annual goal,
6    the participating utility's return on equity shall be
7    reduced by 10 basis points for each such unachieved goal
8    for the following 12-month period.
9        (2) With respect to each of the incremental annual
10    performance goals established pursuant to subparagraphs
11    (2), (3), and (4) of subsection (f) of this Section, as
12    applicable, for each year that the participating utility
13    does not achieve each such goal, the participating
14    utility's return on equity shall be reduced by 5 basis
15    points for each such unachieved goal for the following
16    12-month period. With respect to each of the incremental
17    annual performance goals established pursuant to
18    subparagraph (5) of subsection (f) of this Section, for
19    each year that the participating utility does not achieve
20    at least 95% of each such goal, the participating utility's
21    return on equity shall be reduced by 5 basis points for
22    each such unachieved goal for the following 12-month
23    period.
24        (3) With respect to each of the incremental annual
25    performance goals established pursuant to paragraphs (6),
26    (7), and (8) of subsection (f) of this Section, as

 

 

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1    applicable, the performance under each such goal shall be
2    calculated in terms of the percentage of the goal achieved.
3    The percentage of goal achieved for each of the goals shall
4    be aggregated, and an average percentage value calculated,
5    for each year of the 10-year period. If the utility does
6    not achieve an average percentage value in a given year of
7    at least 95%, the participating utility's return on equity
8    shall be reduced by 5 basis points for the following
9    12-month period.
10    The financial penalties shall be applied as described in
11this subsection (f-5) through a separate tariff mechanism,
12which shall be filed by the utility together with its metrics.
13In the event the formula rate tariff established pursuant to
14subsection (c) of this Section terminates, the utility's
15obligations under subsection (f) of this Section and this
16subsection (f-5) shall also terminate, provided, however, that
17the tariff mechanism established pursuant to subsection (f) of
18this Section and this subsection (f-5) shall remain in effect
19until any penalties due and owing at the time of such
20termination are applied.
21    The Commission shall, after notice and hearing, enter an
22order within 120 days after the metrics are filed approving, or
23approving with modification, a participating utility's tariff
24or mechanism to satisfy the metrics set forth in subsection (f)
25of this Section. On June 1 of each subsequent year, each
26participating utility shall file a report with the Commission

 

 

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1that includes, among other things, a description of how the
2participating utility performed under each metric and an
3identification of any extraordinary events that adversely
4impacted the utility's performance. Whenever a participating
5utility does not satisfy the metrics required pursuant to
6subsection (f) of this Section, the Commission shall, after
7notice and hearing, enter an order approving financial
8penalties in accordance with this subsection (f-5). The
9Commission-approved financial penalties shall be applied
10beginning with the next rate year. Nothing in this Section
11shall authorize the Commission to reduce or otherwise obviate
12the imposition of financial penalties for failing to achieve
13one or more of the metrics established pursuant to subparagraph
14(1) through (4) of subsection (f) of this Section.
15    (g) On or before July 31, 2014, each participating utility
16shall file a report with the Commission that sets forth the
17average annual increase in the average amount paid per
18kilowatthour for residential eligible retail customers,
19exclusive of the effects of energy efficiency programs,
20comparing the 12-month period ending May 31, 2012; the 12-month
21period ending May 31, 2013; and the 12-month period ending May
2231, 2014. For a participating utility that is a combination
23utility with more than one rate zone, the weighted average
24aggregate increase shall be provided. The report shall be filed
25together with a statement from an independent auditor attesting
26to the accuracy of the report. The cost of the independent

 

 

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1auditor shall be borne by the participating utility and shall
2not be a recoverable expense.
3    In the event that the average annual increase exceeds 2.5%
4as calculated pursuant to this subsection (g), then Sections
516-108.5, 16-108.6, 16-108.7, and 16-108.8 of this Act, other
6than this subsection, shall be inoperative as they relate to
7the utility and its service area as of the date of the report
8due to be submitted pursuant to this subsection and the utility
9shall no longer be eligible to annually update the
10performance-based formula rate tariff pursuant to subsection
11(d) of this Section. In such event, the then current rates
12shall remain in effect until such time as new rates are set
13pursuant to Article IX of this Act, subject to retroactive
14adjustment, with interest, to reconcile rates charged with
15actual costs, and the participating utility's voluntary
16commitments and obligations under subsection (b) of this
17Section shall immediately terminate, except for the utility's
18obligation to pay an amount already owed to the fund for
19training grants pursuant to a Commission order issued under
20subsection (b) of this Section.
21    In the event that the average annual increase is 2.5% or
22less as calculated pursuant to this subsection (g), then the
23performance-based formula rate shall remain in effect as set
24forth in this Section.
25    For purposes of this Section, the amount per kilowatthour
26means the total amount paid for electric service expressed on a

 

 

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1per kilowatthour basis, and the total amount paid for electric
2service includes without limitation amounts paid for supply,
3transmission, distribution, surcharges, and add-on taxes
4exclusive of any increases in taxes or new taxes imposed after
5the effective date of this amendatory Act of the 97th General
6Assembly. For purposes of this Section, "eligible retail
7customers" shall have the meaning set forth in Section 16-111.5
8of this Act.
9    The fact that this Section becomes inoperative as set forth
10in this subsection shall not be construed to mean that the
11Commission may reexamine or otherwise reopen prudence or
12reasonableness determinations already made.
13    (h) Sections 16-108.5, 16-108.6, 16-108.7, and 16-108.8 of
14this Act, other than this subsection, are inoperative after
15December 31, 2017 for every participating utility, after which
16time a participating utility shall no longer be eligible to
17annually update the performance-based formula rate tariff
18pursuant to subsection (d) of this Section. At such time, the
19then current rates shall remain in effect until such time as
20new rates are set pursuant to Article IX of this Act, subject
21to retroactive adjustment, with interest, to reconcile rates
22charged with actual costs.
23    By December 31, 2017, the Commission shall prepare and file
24with the General Assembly a report on the infrastructure
25program and the performance-based formula rate. The report
26shall include the change in the average amount per kilowatthour

 

 

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1paid by residential customers between June 1, 2011 and May 31,
22017. If the change in the total average rate paid exceeds 2.5%
3compounded annually, the Commission shall include in the report
4an analysis that shows the portion of the change due to the
5delivery services component and the portion of the change due
6to the supply component of the rate. The report shall include
7separate sections for each participating utility.
8    In the event Sections 16-108.5, 16-108.6, 16-108.7, and
916-108.8 of this Act do not become inoperative after December
1031, 2017, then these Sections are inoperative after December
1131, 2022 for every participating utility, after which time a
12participating utility shall no longer be eligible to annually
13update the performance-based formula rate tariff pursuant to
14subsection (d) of this Section. At such time, the then current
15rates shall remain in effect until such time as new rates are
16set pursuant to Article IX of this Act, subject to retroactive
17adjustment, with interest, to reconcile rates charged with
18actual costs.
19    The fact that this Section becomes inoperative as set forth
20in this subsection shall not be construed to mean that the
21Commission may reexamine or otherwise reopen prudence or
22reasonableness determinations already made.
23    (i) While a participating utility may use, develop, and
24maintain broadband systems and the delivery of broadband
25services, voice-over-internet-protocol services,
26telecommunications services, and cable and video programming

 

 

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1services for use in providing delivery services and Smart Grid
2functionality or application to its retail customers,
3including, but not limited to, the installation,
4implementation and maintenance of Smart Grid electric system
5upgrades as defined in Section 16-108.6 of this Act, a
6participating utility is prohibited from offering to its retail
7customers broadband services or the delivery of broadband
8services, voice-over-internet-protocol services,
9telecommunications services, or cable or video programming
10services, unless they are part of a service directly related to
11delivery services or Smart Grid functionality or applications
12as defined in Section 16-108.6 of this Act, and from recovering
13the costs of such offerings from retail customers.
14    (j) Nothing in this Section is intended to legislatively
15overturn the opinion issued in Commonwealth Edison Co. v. Ill.
16Commerce Comm'n, Nos. 2-08-0959, 2-08-1037, 2-08-1137,
171-08-3008, 1-08-3030, 1-08-3054, 1-08-3313 cons. (Ill. App.
18Ct. 2d Dist. Sept. 30, 2010). This amendatory Act of the 97th
19General Assembly shall not be construed as creating a contract
20between the General Assembly and the participating utility, and
21shall not establish a property right in the participating
22utility.
 
23    (220 ILCS 5/16-108.6 new)
24    Sec. 16-108.6. Provisions relating to Smart Grid Advanced
25Metering Infrastructure Deployment Plan.

 

 

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1    (a) For purposes of this Section and Sections 16-108.7 and
216-108.8 of this Act:
3    "Advanced Metering Infrastructure" or "AMI" means the
4communications hardware and software and associated system
5software that enables Smart Grid functions by creating a
6network between advanced meters and utility business systems
7and allowing collection and distribution of information to
8customers and other parties in addition to providing
9information to the utility itself.
10    "Cost-beneficial" means a determination that the benefits
11of a participating utility's Smart Grid AMI Deployment Plan
12exceed the costs of the Smart Grid AMI Deployment Plan as
13initially filed with the Commission or as subsequently modified
14by the Commission. This standard is met if the present value of
15the total benefits of the Smart Grid AMI Deployment Plan
16exceeds the present value of the total costs of the Smart Grid
17AMI Deployment Plan. The total cost shall include all utility
18costs reasonably associated with the Smart Grid AMI Deployment
19Plan. The total benefits shall include the sum of avoided
20electricity costs, including avoided utility operational
21costs, avoided consumer power, capacity, and energy costs, and
22avoided societal costs associated with the production and
23consumption of electricity, as well as other societal benefits,
24including the greater integration of renewable and distributed
25power resources, reductions in the emissions of harmful
26pollutants and associated avoided health-related costs, other

 

 

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1benefits associated with energy efficiency measures,
2demand-response activities, and the enabling of greater
3penetration of alternative fuel vehicles.
4    "Participating utility" has the meaning set forth in
5Section 16-108.5 of this Act.
6    "Smart Grid" means investments and policies that together
7promote one or more of the following goals:
8        (1) Increased use of digital information and controls
9    technology to improve reliability, security, and
10    efficiency of the electric grid.
11        (2) Dynamic optimization of grid operations and
12    resources, with full cyber security.
13        (3) Deployment and integration of distributed
14    resources and generation, including renewable resources.
15        (4) Development and incorporation of demand-response,
16    demand-side resources, and energy efficiency resources.
17        (5) Deployment of "smart" technologies (real-time,
18    automated, interactive technologies that optimize the
19    physical operation of appliances and consumer devices) for
20    metering, communications concerning grid operations and
21    status, and distribution automation.
22        (6) Integration of "smart" appliances and consumer
23    devices.
24        (7) Deployment and integration of advanced electricity
25    storage and peak-shaving technologies, including plug-in
26    electric and hybrid electric vehicles, thermal-storage air

 

 

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1    conditioning and renewable energy generation.
2        (8) Provision to consumers of timely information and
3    control options.
4        (9) Development of open access standards for
5    communication and interoperability of appliances and
6    equipment connected to the electric grid, including the
7    infrastructure serving the grid.
8        (10) Identification and lowering of unreasonable or
9    unnecessary barriers to adoption of Smart Grid
10    technologies, practices, services, and business models
11    that support energy efficiency, demand-response, and
12    distributed generation.
13    "Smart Grid Advisory Council" means the group of
14stakeholders formed pursuant to subsection (b) of this Section
15for the purposes of advising and working with participating
16utilities on the development and implementation of a Smart Grid
17Advanced Metering Infrastructure Deployment Plan.
18    "Smart Grid electric system upgrades" means any of the
19following:
20        (1) metering devices, sensors, control devices, and
21    other devices integrated with and attached to an electric
22    utility system that are capable of engaging in Smart Grid
23    functions;
24        (2) other monitoring and communications devices that
25    enable Smart Grid functions, including, but not limited to,
26    distribution automation;

 

 

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1        (3) software that enables devices or computers to
2    engage in Smart Grid functions;
3        (4) associated cyber secure data communication
4    network, including enhancements to cyber-security
5    technologies and measures;
6        (5) substation micro-processor relay upgrades;
7        (6) devices that allow electric or hybrid-electric
8    vehicles to engage in Smart Grid functions; or
9        (7) devices that enable individual consumers to
10    incorporate distributed and micro-generation.
11    "Smart Grid electric system upgrades" does not include
12expenditures for: (1) electricity generation, transmission, or
13distribution infrastructure or equipment that does not
14directly relate to or support installing, implementing or
15enabling Smart Grid functions; (2) physical interconnection of
16generators or other devices to the grid except those that are
17directly related to enabling Smart Grid functions; or (3)
18ongoing or routine operation, billing, customer relations,
19security, and maintenance.
20    "Smart Grid functions" means:
21        (1) the ability to develop, store, send, and receive
22    digital information concerning or enabling grid
23    operations, electricity use, costs, prices, time of use,
24    nature of use, storage, or other information relevant to
25    device, grid, or utility operations, to or from or by means
26    of the electric utility system through one or a combination

 

 

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1    of devices and technologies;
2        (2) the ability to develop, store, send, and receive
3    digital information concerning electricity use, costs,
4    prices, time of use, nature of use, storage, or other
5    information relevant to device, grid, or utility
6    operations to or from a computer or other control device;
7        (3) the ability to measure or monitor electricity use
8    as a function of time of day, power quality characteristics
9    such as voltage level, current, cycles per second, or
10    source or type of generation and to store, synthesize, or
11    report that information by digital means;
12        (4) the ability to sense and localize disruptions or
13    changes in power flows on the grid and communicate such
14    information instantaneously and automatically for purposes
15    of enabling automatic protective responses to sustain
16    reliability and security of grid operations;
17        (5) the ability to detect, prevent, communicate with
18    regard to, respond to, or recover from system security
19    threats, including cyber-security threats and terrorism,
20    using digital information, media, and devices;
21        (6) the ability of any device or machine to respond to
22    signals, measurements, or communications automatically or
23    in a manner programmed by its owner or operator without
24    independent human intervention;
25        (7) the ability to use digital information to operate
26    functionalities on the electric utility grid that were

 

 

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1    previously electro-mechanical or manual;
2        (8) the ability to use digital controls to manage and
3    modify electricity demand, enable congestion management,
4    assist in voltage control, provide operating reserves, and
5    provide frequency regulation; or
6        (9) the ability to integrate electric plug-in
7    vehicles, distributed generation, and storage in a safe and
8    cost-effective manner on the electric grid.
9    (b) Within 30 days after the effective date of this
10amendatory Act of the 97th General Assembly, the Smart Grid
11Advisory Council shall be established, which shall consist of 7
12total voting members with each member possessing either
13technical, business or consumer expertise in Smart Grid issues
14and each having been the single appointment of one of the
15following: the Governor, the Speaker of the House, the Minority
16Leader of the House, the President of the Senate, the Minority
17Leader of the Senate, the Illinois Science and Technology
18Coalition, and the Citizens Utility Board. The Governor shall
19designate one of the members of the Council to serve as
20chairman, and that person shall serve as the chairman at the
21pleasure of the Governor. The members shall not be compensated
22for serving on the Smart Grid Advisory Council. The Smart Grid
23Advisory Council shall have the following duties:
24        (1) Serve as an advisor to participating utilities
25    subject to this Section and in the manner described in this
26    Section, and the recommendations provided by the Council,

 

 

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1    although non-binding, shall be considered by the
2    utilities.
3        (2) Serve as trustees of the trust or foundation
4    established pursuant to Section 16-108.7 of this Act with
5    the duties enumerated thereunder.
6    (c) After consultation with the Smart Grid Advisory
7Council, each participating utility shall file a Smart Grid
8Advanced Metering Infrastructure Deployment Plan ("AMI Plan")
9with the Commission within 180 days after the effective date of
10this amendatory Act of the 97th General Assembly or by November
111, 2011, whichever is later, or in the case of a combination
12utility as defined in Section 16-108.5, by April 1, 2012,
13provided that a participating utility shall not file its plan
14until the evaluation report on the Pilot Program described in
15this subsection (c) is issued. The AMI Plan shall provide for
16investment over a 10-year period that is sufficient to
17implement the AMI Plan across its entire service territory in a
18manner that is consistent with subsection (b) of Section
1916-108.5 of this Act. The AMI Plan shall contain:
20        (1) the participating utility's Smart Grid AMI vision
21    statement that is consistent with the goal of developing a
22    cost-beneficial Smart Grid;
23        (2) a statement of Smart Grid AMI strategy that
24    includes a description of how the utility evaluates and
25    prioritizes technology choices to create customer value,
26    including a plan to enhance and enable customers' ability

 

 

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1    to take advantage of Smart Grid functions beginning at the
2    time an account has billed successfully on the AMI network;
3        (3) a deployment schedule and plan that includes
4    deployment of AMI to all customers for a participating
5    utility other than a combination utility, and to 62% of all
6    customers for a participating utility that is a combination
7    utility;
8        (4) annual milestones and metrics for the purposes of
9    measuring the success of the AMI Plan in enabling Smart
10    Grid functions; and enhancing consumer benefits from Smart
11    Grid AMI; and
12        (5) a plan for the consumer education to be implemented
13    by the participating utility.
14    The AMI Plan shall be fully consistent with the standards
15of the National Institute of Standard and Technology (NIST) for
16Smart Grid interoperability that are in effect at the time the
17participating utility files its AMI Plan, shall include open
18standards and internet protocol to the maximum extent possible
19consistent with cyber security, and shall maximize, to the
20extent possible, a flexible smart meter platform that can
21accept remote device upgrades and contain sufficient internal
22memory capacity for additional storage capabilities, functions
23and services without the need for physical access to the meter.
24    The AMI Plan shall secure the privacy of personal
25information and establish the right of consumers to consent to
26the disclosure of personal energy information to third parties

 

 

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1through electronic, web-based, and other means in accordance
2with State and federal law and regulations regarding consumer
3privacy and protection of consumer data.
4    After notice and hearing, the Commission shall, within 60
5days of the filing of an AMI Plan, issue its order approving,
6or approving with modification, the AMI Plan if the Commission
7finds that the AMI Plan contains the information required in
8paragraphs (1) through (5) of this subsection (c) and further
9finds that the implementation of the AMI Plan will be
10cost-beneficial consistent with the principles established
11through the Illinois Smart Grid Collaborative, giving weight to
12the results of any Commission-approved pilot designed to
13examine the benefits and costs of AMI deployment. A
14participating utility's decision to invest pursuant to an AMI
15Plan approved by the Commission shall not be subject to
16prudence reviews in subsequent Commission proceedings. Nothing
17in this subsection (c) is intended to limit the Commission's
18ability to review the reasonableness of the costs incurred
19under the AMI Plan. A participating utility shall be allowed to
20recover the reasonable costs it incurs in implementing a
21Commission-approved AMI Plan, including the costs of retired
22meters, and may recover such costs through its tariffs,
23including the performance-based formula rate tariff approved
24pursuant to subsection (c) of Section 16-108.5 of this Act.
25    (d) The AMI Plan shall secure the privacy of the customer's
26personal information. "Personal information" for this purpose

 

 

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1consists of the customer's name, address, telephone number, and
2other personally identifying information, as well as
3information about the customer's electric usage. Electric
4utilities, their contractors or agents, and any third party who
5comes into possession of such personal information by virtue of
6working on Smart Grid technology shall not disclose such
7personal information to be used in mailing lists or to be used
8for other commercial purposes not reasonably related to the
9conduct of the utility's business. Electric utilities shall
10comply with the consumer privacy requirements of the Personal
11Information Protection Act. In the event a participating
12utility receives revenues from the sale of information obtained
13through Smart Grid technology that is not personal information,
14the participating utility shall use such revenues to offset the
15revenue requirement.
16    (e) On April 1 of each year beginning in 2013 and after
17consultation with the Smart Grid Advisory Council, each
18participating utility shall submit a report regarding the
19progress it has made toward completing implementation of its
20AMI Plan. This report shall:
21        (1) describe the AMI investments made during the prior
22    12 months and the AMI investments planned to be made in the
23    following 12 months;
24        (2) provide sufficient detail to determine the
25    utility's progress in meeting the metrics and milestones
26    identified by the utility in its AMI Plan; and

 

 

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1        (3) identify any updates to the AMI Plan.
2    Within 21 days after the utility files its annual report,
3the Commission shall have authority, either upon complaint or
4its own initiative, but with reasonable notice, to enter upon
5an investigation regarding the utility's progress in
6implementing the AMI Plan as described in paragraph (1) of this
7subsection (e). If the Commission finds, after notice and
8hearing, that the participating utility's progress in
9implementing the AMI Plan is materially deficient for the given
10plan year, then the Commission shall issue an order requiring
11the participating utility to devise a corrective action plan,
12subject to Commission approval and oversight, to bring
13implementation back on schedule consistent with the AMI Plan.
14The Commission's order must be entered within 90 days after the
15utility files its annual report. If the Commission does not
16initiate an investigation within 21 days after the utility
17files its annual report, then the filing shall be deemed
18accepted by the Commission. The utility shall not be required
19to suspend implementation of its AMI Plan during any Commission
20investigation.
21    The participating utility's annual report regarding AMI
22Plan year 10 shall contain a statement verifying that the
23implementation of its AMI Plan is complete, provided, however,
24that if the utility is subject to a corrective action plan that
25extends the implementation period beyond 10 years, the utility
26shall include the verification statement in its final annual

 

 

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1report. Following the date of a Commission order approving the
2final annual report or the date on which the final report is
3deemed accepted by the Commission, the utility's annual
4reporting obligations under this subsection (d) shall
5terminate, provided, however, that the utility shall have a
6continuing obligation to provide information, upon request, to
7the Commission and Smart Grid Advisory Council regarding the
8AMI Plan.
9    (f) Each participating utility shall pay a pro rata share,
10based on number of customers, of $5,000,000 per year to the
11trust or foundation established pursuant to Section 16-108.7 of
12this Act for each plan year of the AMI Plan, which shall be
13used for purposes of providing customer education regarding
14smart meters and related consumer-facing technologies and
15services and 70% of which shall be a recoverable expense;
16provided that other reasonable amounts expended by the utility
17for such consumer education shall not be subject to the 70%
18limitation of this subsection.
19    (g) Within 60 days after the Commission approves a
20participating utility's AMI Plan pursuant to subsection (c) of
21this Section, the participating utility, after consultation
22with the Smart Grid Advisory Council, shall file a proposed
23tariff with the Commission that offers an opt-in market-based
24peak time rebate program to all residential retail customers
25with smart meters that is designed to provide, in a
26competitively neutral manner, rebates to those residential

 

 

SB1652 Enrolled- 118 -LRB097 09323 ASK 49458 b

1retail customers that curtail their use of electricity during
2specific periods that are identified as peak usage periods. The
3total amount of rebates shall be the amount of compensation the
4utility obtains through markets or programs at the applicable
5regional transmission organization. The utility shall make all
6reasonable attempts to secure funding for the peak time rebate
7program through markets or programs at the applicable regional
8transmission organization. The rules and procedures for
9consumers to opt-in to the peak time rebate program shall
10include electronic sign-up, be designed to maximize
11participation, and be included on the utility's website. The
12Commission shall monitor the performance of programs
13established pursuant to this subsection (g) and shall order the
14termination or modification of a program if it determines that
15the program is not, after a reasonable period of time for
16development of at least 4 years, resulting in net benefits to
17the residential customers of the participating utility.
18    (h) If Section 16-108.5 of this Act becomes inoperative
19with respect to one or more participating utilities as set
20forth in subsection (g) or (h) of that Section, then Sections
2116-108.5, 16-108.6, 16-108.7, and 16-108.8 of this Act shall
22become inoperative as to each affected utility and its service
23area on the same date as Section 16-108.5 becomes inoperative.
 
24    (220 ILCS 5/16-108.7 new)
25    Sec. 16-108.7. Illinois Science and Energy Innovation

 

 

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1Trust.
2    (a) Within 90 days of the effective date of this amendatory
3Act of the 97th General Assembly, the members of the Smart Grid
4Advisory Council established pursuant to Section 16-108.6 of
5this Act, or a majority of the members thereof, shall cause to
6be established an Illinois science and energy innovation trust
7or foundation for the purposes of providing financial and
8technical support and assistance to entities, public or
9private, within the State of Illinois including, but not
10limited to, units of State and local government, educational
11and research institutions, corporations, and charitable,
12educational, environmental and community organizations, for
13programs and projects that support, encourage or utilize
14innovative technologies or other methods of modernizing the
15State's electric grid that will benefit the public by promoting
16economic development in Illinois. Such activities shall be
17supported through grants, loans, contracts, or other programs
18designed to assist and further benefit technological advances
19in the area of electric grid modernization and operation. The
20trust or foundation shall also be eligible for receipt of other
21energy and environmental grant opportunities, from public or
22private sources. The trust or foundation shall not be a
23governmental entity.
24    (b) Funds received by the trust or foundation pursuant to
25subsection (f) of Section 16-108.6 of this Act shall be used
26solely for the purpose of providing consumer education

 

 

SB1652 Enrolled- 120 -LRB097 09323 ASK 49458 b

1regarding smart meters and related consumer-facing
2technologies and services and the peak time rebate program
3described in subsection (g) of Section 16-108.6 of this Act.
4Thirty percent of such funds received from each participating
5utility shall be used by the trust or foundation for purposes
6of providing such education to each participating utility's
7low-income retail customers, including low-income senior
8citizens.
9    The trust or foundation shall use all funds received
10pursuant to subsection (f) of Section 16-108.6 of this Act in a
11manner that reflects the unique needs and characteristics of
12each participating utility's service territory and in
13proportion to each participating utility's payment.
14    (c) Such trust or foundation shall be governed by a
15declaration of trust or articles of incorporation and bylaws
16which shall, at a minimum, provide the following:
17        (1) There shall initially be 7 trustees of the trust or
18    foundation, which shall consist of the members of the Smart
19    Grid Advisory Council established pursuant to Section
20    16-108.6 of this Act. Subsequently, the participating
21    utilities shall appoint one trustee and the Clean Energy
22    Trust shall appoint one non-voting trustee who shall
23    provide expertise regarding early stage investment in
24    Smart Grid projects.
25        (2) All trustees shall be entitled to reimbursement for
26    reasonable expenses incurred on behalf of the trust in the

 

 

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1    performance of their duties as trustees. All such
2    reimbursements shall be paid out of the trust.
3        (3) Trustees shall be appointed within 60 days after
4    the creation of the trust or foundation and shall serve for
5    a term of 5 years commencing upon the date of their
6    respective appointments, until their respective successors
7    are appointed and qualified.
8        (4) A vacancy in the office of trustee shall be filled
9    by the person holding the office responsible for appointing
10    the trustee whose death or resignation creates the vacancy,
11    and a trustee appointed to fill a vacancy shall serve the
12    remainder of the term of the trustee whose resignation or
13    death created the vacancy.
14        (5) The trust or foundation shall have an indefinite
15    term and shall terminate at such time as no trust assets
16    remain.
17        (6) The allocation and disbursement of funds for the
18    various purposes for which the trust or foundation is
19    established shall be determined by the trustees in
20    accordance with the declaration of trust or the articles of
21    incorporation and bylaws.
22        (7) The trust or foundation shall be authorized to
23    employ an executive director and other employees, or
24    contract management of the trust or foundation in its
25    entirety to an outside organization found suitable by the
26    trustees, to enter into leases, contracts and other

 

 

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1    obligations on behalf of the trust or foundation, and to
2    incur expenses that the trustees deem necessary or
3    appropriate for the fulfillment of the purposes for which
4    the trust or foundation is established, provided, however,
5    that salaries and administrative expenses incurred on
6    behalf of the trust or foundation shall not exceed 3% of
7    the trust's principal value, or $750,000, whichever is
8    greater, in any given year. The trustees shall not be
9    compensated by the trust or foundation.
10        (8) The trustees may create and appoint advisory boards
11    or committees to assist them with the administration of the
12    trust or foundation, and to advise and make recommendations
13    to them regarding the contribution and disbursement of the
14    trust or foundation funds.
15        (9) All funds dispersed by the trust or foundation for
16    programs and projects to meet the objectives of the trust
17    or foundation as enumerated in this Section shall be
18    subject to a peer-review process as determined by the
19    trustees. This process shall be designed to determine, in
20    an objective and unbiased manner, those programs and
21    projects that best fit the objectives of the trust or
22    foundation. In each fiscal year the trustees shall
23    determine, based solely on the information provided
24    through the peer-review process, a budget for programs and
25    projects for that fiscal year.
26        (10) The trustees shall administer a Smart Grid

 

 

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1    education fund from which it shall make grants to qualified
2    not-for-profit organizations for the purpose of educating
3    customers with regard to smart meters and related
4    consumer-facing technologies and services. In making such
5    grants the trust or foundation shall strongly encourage
6    grantees to coordinate to the extent practicable and
7    consider recommendations from the participating utilities
8    regarding the development and implementation of customer
9    education plans.
10        (11) One of the objectives of the trust or foundation
11    is to remain self-funding. In order to meet this objective,
12    the trustees may sign agreements with those entities
13    receiving funding that provide for license fees,
14    royalties, or other payments to the trust or foundation
15    from such entities that receive support for their product
16    development from the trust or foundation. Such payments,
17    however, shall be contingent on the commercialization of
18    such products, services, or technologies enabled by the
19    funding provided by the trust or foundation.
20    (d) The trustees shall notify each participating utility as
21defined in Section 16-108.5 of this Act of the formation of the
22trust or foundation. Within 90 days after receipt of the
23notification, each participating utility that is not a
24combination utility as defined in Section 16-108.5 of this Act
25shall contribute $15,000,000 to the trust or foundation, and
26each participating utility that is a combination utility, as

 

 

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1defined in Section 16-108.5 of this Act, shall contribute
2$7,500,000 to the trust or foundation established pursuant to
3this Section. Such contributions shall not be a recoverable
4expense.
5    (e) If Section 16-108.5 of this Act becomes inoperative
6with respect to one or more participating utilities as set
7forth in subsection (g) or (h) of that Section, then Sections
816-108.5, 16-108.6, 16-108.7, and 16-108.8 of this Act shall
9become inoperative as to each affected utility and its service
10area on the same date as Section 16-108.5 becomes inoperative.
 
11    (220 ILCS 5/16-108.8 new)
12    Sec. 16-108.8. Illinois Smart Grid test bed.
13    (a) Within 180 days after the effective date of this
14amendatory Act of the 97th General Assembly, each participating
15utility, as defined by Section 16-108.5 of this Act, shall
16create or otherwise designate a Smart Grid test bed, which may
17be located at one or more places within the utility's system,
18for the purposes of allowing for the testing of Smart Grid
19technologies. The objectives of this test bed shall be to:
20        (1) provide an open, unbiased opportunity for testing
21    programs, technologies, business models, and other Smart
22    Grid-related activities;
23        (2) provide on-grid locations for the testing of
24    potentially innovative Smart Grid-related technologies and
25    services, including but not limited to those funded by the

 

 

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1    trust or foundation established pursuant to Section
2    16-108.7 of this Act;
3        (3) facilitate testing of business models or services
4    that help integrate Smart Grid-related technologies into
5    the electric grid, especially those business models that
6    may help promote new products and services for retail
7    customers;
8        (4) offer opportunities to test and showcase Smart Grid
9    technologies and services, especially those likely to
10    support the economic development goals of the State of
11    Illinois.
12    (b) The test bed shall reside in one or more locations on
13the participating utility's network. Such locations shall be
14chosen by the utility to maximize the opportunity for real-time
15and real-world testing of Smart Grid technologies and services
16taking into account the safety and security of the
17participating utility's grid and grid operations.
18    (c) The participating utility, with input from the Smart
19Grid Advisory Council established pursuant to Section 16-108.6
20of this Act, shall, as part of its filing under subsection (b)
21of Section 16-108.5, include a plan for the creation,
22operation, and administration of the test bed. This plan shall
23address the following:
24        (1) how the utility proposes to comply with each of the
25    objectives set forth in subsection (a) of this Section;
26        (2) the proposed location or locations of the test bed;

 

 

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1        (3) the process by which the utility will receive,
2    review, and qualify proposals to use the test bed;
3        (4) the criteria by which the utility proposes to
4    qualify proposals to use the test bed, including, but not
5    limited to, safety, reliability, security, customer data
6    security, privacy, and economic development
7    considerations;
8        (5) the engineering and operations support that the
9    utility will provide to test bed users, including provision
10    of customer data; and
11        (6) the estimated costs to establish, administer and
12    promote the availability of the test bed.
13    (d) The test bed should be open to all qualified entities
14wishing to test programs, technologies, business models, and
15other Smart Grid-related activities, provided that the utility
16retains control of its grid and operations and may reject any
17programs, technologies, business models, and other Smart
18Grid-related activities that threaten the reliability, safety,
19security, or operations of its network, or that would threaten
20the security of customer-identifiable data in the judgment of
21the utility. The number of technologies and entities
22participating in the test bed at any time may be limited by the
23utility based on its determination of its ability to maintain a
24secure, safe, and reliable grid.
25    (e) At a minimum, the test bed shall have the ability to
26receive live signals from PJM Interconnection LLC or other

 

 

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1applicable regional transmission organization, the ability to
2test new applications in a utility scale environment (to
3include ramp rate regulations for distributed wind and solar
4resources), critical peak price response, and market-based
5power dispatch.
6    (f) At the end of the fourth year of operation the test bed
7shall be subject to an independent evaluation to determine if
8the test bed is meeting the objectives of this Section or is
9likely to meet the objectives in the future. The evaluation
10shall include the performance of the utility as test bed
11operator. Subject to the findings, the utility and the trust or
12foundation established pursuant to Section 16-108.7 of this Act
13may choose to continue operating the test bed.
14    (g) The utility shall be entitled to recover all prudently
15incurred and reasonable costs associated with evaluation of
16proposals, engineering, construction, operation, and
17administration of the test bed through the performance-based
18formula rate tariff established pursuant to Section 16-108.5 of
19this Act.
20    (h) The utility is authorized to charge fees to users of
21the test bed that shall recover the costs associated with the
22incremental costs to the utility associated with
23administration of the test bed, provided, however, that any
24such fees collected by the utility shall be used to offset the
25costs to be recovered pursuant to subsection (g) of this
26Section.

 

 

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1    (i) On a quarterly basis, the utility shall provide the
2trust or foundation established pursuant to Section 16-108.7 of
3this Act with a report summarizing test bed activities,
4customers, discoveries, and other information as shall be
5mutually deemed relevant.
6    (j) To the extent practicable, the utility and trust or
7foundation established pursuant to Section 16-108.7 of this Act
8shall jointly pursue resources that enhance the capabilities
9and capacity of the test bed.
10    (k) If Section 16-108.5 of this Act becomes inoperative
11with respect to one or more participating utilities as set
12forth in subsection (g) or (h) of that Section, then Sections
1316-108.5, 16-108.6, 16-108.7, and 16-108.8 of this Act shall
14become inoperative as to each affected utility and its service
15area on the same date as Section 16-108.5 become inoperative.
 
16    (220 ILCS 5/16-111.5)
17    Sec. 16-111.5. Provisions relating to procurement.
18    (a) An electric utility that on December 31, 2005 served at
19least 100,000 customers in Illinois shall procure power and
20energy for its eligible retail customers in accordance with the
21applicable provisions set forth in Section 1-75 of the Illinois
22Power Agency Act and this Section. "Eligible retail customers"
23for the purposes of this Section means those retail customers
24that purchase power and energy from the electric utility under
25fixed-price bundled service tariffs, other than those retail

 

 

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

 

 

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

 

 

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1        current and projected;
2            (ii) supply side needs that are projected to be
3        offset by purchases of renewable energy resources, if
4        any; and
5            (iii) the impact of energy efficiency programs,
6        both current and projected.
7        (3) A plan for meeting the expected load requirements
8    that will not be met through preexisting contracts. This
9    plan shall include:
10            (i) definitions of the different retail customer
11        classes for which supply is being purchased;
12            (ii) the proposed mix of demand-response products
13        for which contracts will be executed during the next
14        year. The cost-effective demand-response measures
15        shall be procured whenever the cost is lower than
16        procuring comparable capacity products, provided that
17        such products shall:
18                (A) be procured by a demand-response provider
19            from eligible retail customers;
20                (B) at least satisfy the demand-response
21            requirements of the regional transmission
22            organization market in which the utility's service
23            territory is located, including, but not limited
24            to, any applicable capacity or dispatch
25            requirements;
26                (C) provide for customers' participation in

 

 

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

 

 

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1        portfolio of products; and
2            (vi) an assessment of the price risk, load
3        uncertainty, and other factors that are associated
4        with the proposed procurement plan; this assessment,
5        to the extent possible, shall include an analysis of
6        the following factors: contract terms, time frames for
7        securing products or services, fuel costs, weather
8        patterns, transmission costs, market conditions, and
9        the governmental regulatory environment; the proposed
10        procurement plan shall also identify alternatives for
11        those portfolio measures that are identified as having
12        significant price risk.
13        (4) Proposed procedures for balancing loads. The
14    procurement plan shall include, for load requirements
15    included in the procurement plan, the process for (i)
16    hourly balancing of supply and demand and (ii) the criteria
17    for portfolio re-balancing in the event of significant
18    shifts in load.
19    (c) The procurement process set forth in Section 1-75 of
20the Illinois Power Agency Act and subsection (e) of this
21Section shall be administered by a procurement administrator
22and monitored by a procurement monitor.
23        (1) The procurement administrator shall:
24            (i) design the final procurement process in
25        accordance with Section 1-75 of the Illinois Power
26        Agency Act and subsection (e) of this Section following

 

 

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

 

 

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

 

 

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1            (vi) provide expert advice to the Commission and
2        consult with the procurement administrator regarding
3        issues related to procurement process design, rules,
4        protocols, and policy-related matters; and
5            (vii) consult with the procurement administrator
6        regarding the development and use of benchmark
7        criteria, standard form contracts, credit policies,
8        and bid documents.
9    (d) Except as provided in subsection (j), the planning
10process shall be conducted as follows:
11        (1) Beginning in 2008, each Illinois utility procuring
12    power pursuant to this Section shall annually provide a
13    range of load forecasts to the Illinois Power Agency by
14    July 15 of each year, or such other date as may be required
15    by the Commission or Agency. The load forecasts shall cover
16    the 5-year procurement planning period for the next
17    procurement plan and shall include hourly data
18    representing a high-load, low-load and expected-load
19    scenario for the load of the eligible retail customers. The
20    utility shall provide supporting data and assumptions for
21    each of the scenarios.
22        (2) Beginning in 2008, the Illinois Power Agency shall
23    prepare a procurement plan by August 15th of each year, or
24    such other date as may be required by the Commission. The
25    procurement plan shall identify the portfolio of
26    demand-response and power and energy products to be

 

 

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

 

 

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1    hearing is necessary. The Commission shall enter its order
2    confirming or modifying the procurement plan within 90 days
3    after the filing of the procurement plan by the Illinois
4    Power Agency.
5        (4) The Commission shall approve the procurement plan,
6    including expressly the forecast used in the procurement
7    plan, if the Commission determines that it will ensure
8    adequate, reliable, affordable, efficient, and
9    environmentally sustainable electric service at the lowest
10    total cost over time, taking into account any benefits of
11    price stability.
12    (e) The procurement process shall include each of the
13following components:
14        (1) Solicitation, pre-qualification, and registration
15    of bidders. The procurement administrator shall
16    disseminate information to potential bidders to promote a
17    procurement event, notify potential bidders that the
18    procurement administrator may enter into a post-bid price
19    negotiation with bidders that meet the applicable
20    benchmarks, provide supply requirements, and otherwise
21    explain the competitive procurement process. In addition
22    to such other publication as the procurement administrator
23    determines is appropriate, this information shall be
24    posted on the Illinois Power Agency's and the Commission's
25    websites. The procurement administrator shall also
26    administer the prequalification process, including

 

 

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1    evaluation of credit worthiness, compliance with
2    procurement rules, and agreement to the standard form
3    contract developed pursuant to paragraph (2) of this
4    subsection (e). The procurement administrator shall then
5    identify and register bidders to participate in the
6    procurement event.
7        (2) Standard contract forms and credit terms and
8    instruments. The procurement administrator, in
9    consultation with the utilities, the Commission, and other
10    interested parties and subject to Commission oversight,
11    shall develop and provide standard contract forms for the
12    supplier contracts that meet generally accepted industry
13    practices. Standard credit terms and instruments that meet
14    generally accepted industry practices shall be similarly
15    developed. The procurement administrator shall make
16    available to the Commission all written comments it
17    receives on the contract forms, credit terms, or
18    instruments. If the procurement administrator cannot reach
19    agreement with the applicable electric utility as to the
20    contract terms and conditions, the procurement
21    administrator must notify the Commission of any disputed
22    terms and the Commission shall resolve the dispute. The
23    terms of the contracts shall not be subject to negotiation
24    by winning bidders, and the bidders must agree to the terms
25    of the contract in advance so that winning bids are
26    selected solely on the basis of price.

 

 

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1        (3) Establishment of a market-based price benchmark.
2    As part of the development of the procurement process, the
3    procurement administrator, in consultation with the
4    Commission staff, Agency staff, and the procurement
5    monitor, shall establish benchmarks for evaluating the
6    final prices in the contracts for each of the products that
7    will be procured through the procurement process. The
8    benchmarks shall be based on price data for similar
9    products for the same delivery period and same delivery
10    hub, or other delivery hubs after adjusting for that
11    difference. The price benchmarks may also be adjusted to
12    take into account differences between the information
13    reflected in the underlying data sources and the specific
14    products and procurement process being used to procure
15    power for the Illinois utilities. The benchmarks shall be
16    confidential but shall be provided to, and will be subject
17    to Commission review and approval, prior to a procurement
18    event.
19        (4) Request for proposals competitive procurement
20    process. The procurement administrator shall design and
21    issue a request for proposals to supply electricity in
22    accordance with each utility's procurement plan, as
23    approved by the Commission. The request for proposals shall
24    set forth a procedure for sealed, binding commitment
25    bidding with pay-as-bid settlement, and provision for
26    selection of bids on the basis of price.

 

 

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

 

 

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1        organization market it shall be purchased from the
2        wholesale market.
3            (ii) Failure of the procurement process to fully
4        meet the expected load requirement: If the procurement
5        process fails to fully meet the expected load
6        requirement due to insufficient supplier participation
7        or due to a Commission rejection of the procurement
8        results, the procurement administrator, the
9        procurement monitor, and the Commission staff shall
10        meet within 10 days to analyze potential causes of low
11        supplier interest or causes for the Commission
12        decision. If changes are identified that would likely
13        result in increased supplier participation, or that
14        would address concerns causing the Commission to
15        reject the results of the prior procurement event, the
16        procurement administrator may implement those changes
17        and rerun the request for proposals process according
18        to a schedule determined by those parties and
19        consistent with Section 1-75 of the Illinois Power
20        Agency Act and this subsection. In any event, a new
21        request for proposals process shall be implemented by
22        the procurement administrator within 90 days after the
23        determination that the procurement process has failed
24        to fully meet the expected load requirement.
25            (iii) In all cases where there is insufficient
26        supply provided under contracts awarded through the

 

 

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1        procurement process to fully meet the electric
2        utility's load requirement, the utility shall meet the
3        load requirement by procuring power and energy from the
4        applicable regional transmission organization market,
5        including ancillary services, capacity, and day-ahead
6        or real time energy or both; provided, however, that if
7        a needed product is not available through the regional
8        transmission organization market it shall be purchased
9        from the wholesale market.
10        (6) The procurement process described in this
11    subsection is exempt from the requirements of the Illinois
12    Procurement Code, pursuant to Section 20-10 of that Code.
13    (f) Within 2 business days after opening the sealed bids,
14the procurement administrator shall submit a confidential
15report to the Commission. The report shall contain the results
16of the bidding for each of the products along with the
17procurement administrator's recommendation for the acceptance
18and rejection of bids based on the price benchmark criteria and
19other factors observed in the process. The procurement monitor
20also shall submit a confidential report to the Commission
21within 2 business days after opening the sealed bids. The
22report shall contain the procurement monitor's assessment of
23bidder behavior in the process as well as an assessment of the
24procurement administrator's compliance with the procurement
25process and rules. The Commission shall review the confidential
26reports submitted by the procurement administrator and

 

 

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1procurement monitor, and shall accept or reject the
2recommendations of the procurement administrator within 2
3business days after receipt of the reports.
4    (g) Within 3 business days after the Commission decision
5approving the results of a procurement event, the utility shall
6enter into binding contractual arrangements with the winning
7suppliers using the standard form contracts; except that the
8utility shall not be required either directly or indirectly to
9execute the contracts if a tariff that is consistent with
10subsection (l) of this Section has not been approved and placed
11into effect for that utility.
12    (h) The names of the successful bidders and the load
13weighted average of the winning bid prices for each contract
14type and for each contract term shall be made available to the
15public at the time of Commission approval of a procurement
16event. The Commission, the procurement monitor, the
17procurement administrator, the Illinois Power Agency, and all
18participants in the procurement process shall maintain the
19confidentiality of all other supplier and bidding information
20in a manner consistent with all applicable laws, rules,
21regulations, and tariffs. Confidential information, including
22the confidential reports submitted by the procurement
23administrator and procurement monitor pursuant to subsection
24(f) of this Section, shall not be made publicly available and
25shall not be discoverable by any party in any proceeding,
26absent a compelling demonstration of need, nor shall those

 

 

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1reports be admissible in any proceeding other than one for law
2enforcement purposes.
3    (i) Within 2 business days after a Commission decision
4approving the results of a procurement event or such other date
5as may be required by the Commission from time to time, the
6utility shall file for informational purposes with the
7Commission its actual or estimated retail supply charges, as
8applicable, by customer supply group reflecting the costs
9associated with the procurement and computed in accordance with
10the tariffs filed pursuant to subsection (l) of this Section
11and approved by the Commission.
12    (j) Within 60 days following the effective date of this
13amendatory Act, each electric utility that on December 31, 2005
14provided electric service to at least 100,000 customers in
15Illinois shall prepare and file with the Commission an initial
16procurement plan, which shall conform in all material respects
17to the requirements of the procurement plan set forth in
18subsection (b); provided, however, that the Illinois Power
19Agency Act shall not apply to the initial procurement plan
20prepared pursuant to this subsection. The initial procurement
21plan shall identify the portfolio of power and energy products
22to be procured and delivered for the period June 2008 through
23May 2009, and shall identify the proposed procurement
24administrator, who shall have the same experience and expertise
25as is required of a procurement administrator hired pursuant to
26Section 1-75 of the Illinois Power Agency Act. Copies of the

 

 

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1procurement plan shall be posted and made publicly available on
2the Commission's website. The initial procurement plan may
3include contracts for renewable resources that extend beyond
4May 2009.
5        (i) Within 14 days following filing of the initial
6    procurement plan, any person may file a detailed objection
7    with the Commission contesting the procurement plan
8    submitted by the electric utility. All objections to the
9    electric utility's plan shall be specific, supported by
10    data or other detailed analyses. The electric utility may
11    file a response to any objections to its procurement plan
12    within 7 days after the date objections are due to be
13    filed. Within 7 days after the date the utility's response
14    is due, the Commission shall determine whether a hearing is
15    necessary. If it determines that a hearing is necessary, it
16    shall require the hearing to be completed and issue an
17    order on the procurement plan within 60 days after the
18    filing of the procurement plan by the electric utility.
19        (ii) The order shall approve or modify the procurement
20    plan, approve an independent procurement administrator,
21    and approve or modify the electric utility's tariffs that
22    are proposed with the initial procurement plan. The
23    Commission shall approve the procurement plan if the
24    Commission determines that it will ensure adequate,
25    reliable, affordable, efficient, and environmentally
26    sustainable electric service at the lowest total cost over

 

 

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1    time, taking into account any benefits of price stability.
2    (k) In order to promote price stability for residential and
3small commercial customers during the transition to
4competition in Illinois, and notwithstanding any other
5provision of this Act, each electric utility subject to this
6Section shall enter into one or more multi-year financial swap
7contracts that become effective on the effective date of this
8amendatory Act. These contracts may be executed with generators
9and power marketers, including affiliated interests of the
10electric utility. These contracts shall be for a term of no
11more than 5 years and shall, for each respective utility or for
12any Illinois electric utilities that are affiliated by virtue
13of a common parent company and that are thereby considered a
14single electric utility for purposes of this subsection (k),
15not exceed in the aggregate 3,000 megawatts for any hour of the
16year. The contracts shall be financial contracts and not energy
17sales contracts. The contracts shall be executed as
18transactions under a negotiated master agreement based on the
19form of master agreement for financial swap contracts sponsored
20by the International Swaps and Derivatives Association, Inc.
21and shall be considered pre-existing contracts in the
22utilities' procurement plans for residential and small
23commercial customers. Costs incurred pursuant to a contract
24authorized by this subsection (k) shall be deemed prudently
25incurred and reasonable in amount and the electric utility
26shall be entitled to full cost recovery pursuant to the tariffs

 

 

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1filed with the Commission.
2    (k-5) In order to promote price stability for residential
3and small commercial customers during the infrastructure
4investment program described in subsection (b) of Section
516-108.5 of this Act, and notwithstanding any other provision
6of this Act or the Illinois Power Agency Act, for each electric
7utility that serves more than one million retail customers in
8Illinois, the Illinois Power Agency shall conduct a procurement
9event within 120 days after the effective date of this
10amendatory Act of the 97th General Assembly and may procure
11contracts for energy and renewable energy credits for the
12period June 1, 2013 through December 31, 2017 that satisfy the
13requirements of this subsection (k-5), including the
14benchmarks described in this subsection. These contracts shall
15be entered into as the result of a competitive procurement
16event, and, to the extent that any provisions of this Section
17or the Illinois Power Agency Act do not conflict with this
18subsection (k-5), such provisions shall apply to the
19procurement event. The energy contracts shall be for 24 hour by
207 day supply over a term that runs from the first delivery year
21through December 31, 2017. For a utility that serves over 2
22million customers, the energy contracts shall be multi-year
23with pricing escalating at 2.5% per annum. The energy contracts
24may be designed as financial swaps or may require physical
25delivery.
26    Within 30 days of the effective date of this amendatory Act

 

 

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1of the 97th General Assembly, each such utility shall submit to
2the Agency updated load forecasts for the period June 1, 2013
3through December 31, 2017. The megawatt volume of the contracts
4shall be based on the updated load forecasts of the minimum
5monthly on-peak or off-peak average load requirements shown in
6the forecasts, taking into account any existing energy
7contracts in effect as well as the expected migration of the
8utility's customers to alternative retail electric suppliers.
9The renewable energy credit volume shall be based on the number
10of credits that would satisfy the requirements of subsection
11(c) of Section 1-75 of the Illinois Power Agency Act, subject
12to the rate impact caps and other provisions of subsection (c)
13of Section 1-75 of the Illinois Power Agency Act. The
14evaluation of contract bids in the competitive procurement
15events for energy and for renewable energy credits shall
16incorporate price benchmarks set collaboratively by the
17Agency, the procurement administrator, the staff of the
18Commission, and the procurement monitor. If the contracts are
19swap contracts, then they shall be executed as transactions
20under a negotiated master agreement based on the form of master
21agreement for financial swap contracts sponsored by the
22International Swaps and Derivatives Association, Inc. Costs
23incurred pursuant to a contract authorized by this subsection
24(k-5) shall be deemed prudently incurred and reasonable in
25amount and the electric utility shall be entitled to full cost
26recovery pursuant to the tariffs filed with the Commission.

 

 

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1    The cost of administering the procurement event described
2in this subsection (k-5) shall be paid by the winning supplier
3or suppliers to the procurement administrator through a
4supplier fee. In the event that there is no winning supplier
5for a particular utility, such utility will pay the procurement
6administrator for the costs associated with the procurement
7event, and those costs shall not be a recoverable expense.
8Nothing in this subsection (k-5) is intended to alter the
9recovery of costs for any other procurement event.
10    (l) An electric utility shall recover its costs incurred
11under this Section, including, but not limited to, the costs of
12procuring power and energy demand-response resources under
13this Section. The utility shall file with the initial
14procurement plan its proposed tariffs through which its costs
15of procuring power that are incurred pursuant to a
16Commission-approved procurement plan and those other costs
17identified in this subsection (l), will be recovered. The
18tariffs shall include a formula rate or charge designed to pass
19through both the costs incurred by the utility in procuring a
20supply of electric power and energy for the applicable customer
21classes with no mark-up or return on the price paid by the
22utility for that supply, plus any just and reasonable costs
23that the utility incurs in arranging and providing for the
24supply of electric power and energy. The formula rate or charge
25shall also contain provisions that ensure that its application
26does not result in over or under recovery due to changes in

 

 

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1customer usage and demand patterns, and that provide for the
2correction, on at least an annual basis, of any accounting
3errors that may occur. A utility shall recover through the
4tariff all reasonable costs incurred to implement or comply
5with any procurement plan that is developed and put into effect
6pursuant to Section 1-75 of the Illinois Power Agency Act and
7this Section, including any fees assessed by the Illinois Power
8Agency, costs associated with load balancing, and contingency
9plan costs. The electric utility shall also recover its full
10costs of procuring electric supply for which it contracted
11before the effective date of this Section in conjunction with
12the provision of full requirements service under fixed-price
13bundled service tariffs subsequent to December 31, 2006. All
14such costs shall be deemed to have been prudently incurred. The
15pass-through tariffs that are filed and approved pursuant to
16this Section shall not be subject to review under, or in any
17way limited by, Section 16-111(i) of this Act.
18    (m) The Commission has the authority to adopt rules to
19carry out the provisions of this Section. For the public
20interest, safety, and welfare, the Commission also has
21authority to adopt rules to carry out the provisions of this
22Section on an emergency basis immediately following the
23effective date of this amendatory Act.
24    (n) Notwithstanding any other provision of this Act, any
25affiliated electric utilities that submit a single procurement
26plan covering their combined needs may procure for those

 

 

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

 

 

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1generation facility through just and reasonable rates charged
2to eligible retail customers. Cost recovery for facilities
3included in the utility's procurement plan pursuant to this
4subsection shall not be subject to review under or in any way
5limited by the provisions of Section 16-111(i) of this Act.
6Nothing in this Section is intended to prohibit a utility from
7filing for a fuel adjustment clause as is otherwise permitted
8under Section 9-220 of this Act.
9(Source: P.A. 95-481, eff. 8-28-07; 95-1027, eff. 6-1-09.)
 
10    (220 ILCS 5/16-111.5B new)
11    Sec. 16-111.5B. Provisions relating to energy efficiency
12procurement.
13    (a) Beginning in 2012, procurement plans prepared pursuant
14to Section 16-111.5 of this Act shall be subject to the
15following additional requirements:
16        (1) The analysis included pursuant to paragraph (2) of
17    subsection (b) of Section 16-111.5 shall also include the
18    impact of energy efficiency building codes or appliance
19    standards, both current and projected.
20        (2) The procurement plan components described in
21    subsection (b) of Section 16-111.5 shall also include an
22    assessment of opportunities to expand the programs
23    promoting energy efficiency measures that have been
24    offered under plans approved pursuant to Section 8-103 of
25    this Act or to implement additional cost-effective energy

 

 

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1    efficiency programs or measures.
2        (3) In addition to the information provided pursuant to
3    paragraph (1) of subsection (d) of Section 16-111.5 of this
4    Act, each Illinois utility procuring power pursuant to that
5    Section shall annually provide to the Illinois Power Agency
6    by July 15 of each year, or such other date as may be
7    required by the Commission or Agency, an assessment of
8    cost-effective energy efficiency programs or measures that
9    could be included in the procurement plan. The assessment
10    shall include the following:
11            (A) A comprehensive energy efficiency potential
12        study for the utility's service territory that was
13        completed within the past 3 years.
14            (B) Beginning in 2014, the most recent analysis
15        submitted pursuant to Section 8-103A of this Act and
16        approved by the Commission under subsection (f) of
17        Section 8-103 of this Act.
18            (C) Identification of new or expanded
19        cost-effective energy efficiency programs or measures
20        that are incremental to those included in energy
21        efficiency and demand-response plans approved by the
22        Commission pursuant to Section 8-103 of this Act and
23        that would be offered to eligible retail customers.
24            (D) Analysis showing that the new or expanded
25        cost-effective energy efficiency programs or measures
26        would lead to a reduction in the overall cost of

 

 

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1        electric service.
2            (E) Analysis of how the cost of procuring
3        additional cost-effective energy efficiency measures
4        compares over the life of the measures to the
5        prevailing cost of comparable supply.
6            (F) An energy savings goal, expressed in
7        megawatt-hours, for the year in which the measures will
8        be implemented.
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.
20        (6) An electric utility shall recover its costs
21    incurred under this Section related to the implementation
22    of energy efficiency programs and measures approved by the
23    Commission in its order approving the procurement plan
24    under Section 16-111.5 of this Act, including, but not
25    limited to, all costs associated with complying with this
26    Section and all start-up and administrative costs and the

 

 

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1    costs for any evaluation, measurement, and verification of
2    the measures, from eligible retail customers through the
3    automatic adjustment clause tariff established pursuant to
4    Section 8-103 of this Act, provided, however, that the
5    limitations described in subsection (d) of that Section
6    shall not apply to the costs incurred pursuant to this
7    Section or Section 16-111.7 of this Act.
8    (b) For purposes of this Section, the term "energy
9efficiency" shall have the meaning set forth in Section 1-10 of
10the Illinois Power Agency Act, and the term "cost-effective"
11shall have the meaning set forth in subsection (a) of Section
128-103 of this Act. In addition, the estimated costs to acquire
13an additional energy efficiency measure, when divided by the
14number of kilowatt-hours expected to be saved over the life of
15the measure, shall be less than or equal to the electricity
16costs that would be avoided as a result of the energy
17efficiency measure.
 
18    (220 ILCS 5/16-111.7)
19    Sec. 16-111.7. On-bill financing program; electric
20utilities.
21    (a) The Illinois General Assembly finds that Illinois homes
22and businesses have the potential to save energy through
23conservation and cost-effective energy efficiency measures.
24Programs created pursuant to this Section will allow utility
25customers to purchase cost-effective energy efficiency

 

 

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1measures, including measures set forth in a
2Commission-approved energy efficiency and demand-response plan
3under Section 8-103 of this Act and that are cost-effective as
4that term is defined by that Section, with no required initial
5upfront payment, and to pay the cost of those products and
6services over time on their utility bill.
7    (b) Notwithstanding any other provision of this Act, an
8electric utility serving more than 100,000 customers on January
91, 2009 shall offer a Commission-approved on-bill financing
10program ("program") that allows its eligible retail customers,
11as that term is defined in Section 16-111.5 of this Act, who
12own a residential single family home, duplex, or other
13residential building with 4 or less units, or condominium at
14which the electric service is being provided (i) to borrow
15funds from a third party lender in order to purchase electric
16energy efficiency measures approved under the program for
17installation in such home or condominium without any required
18upfront payment and (ii) to pay back such funds over time
19through the electric utility's bill. Based upon the process
20described in subsection (b-5) of this Section, small commercial
21retail customers, as that term is defined in Section 16-102 of
22this Act, who own the premises at which electric service is
23being provided may be included in such program. After receiving
24a request from an electric utility for approval of a proposed
25program and tariffs pursuant to this Section, the Commission
26shall render its decision within 120 days. If no decision is

 

 

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1rendered within 120 days, then the request shall be deemed to
2be approved.
3    (b-5) Within 30 days after the effective date of this
4amendatory Act of the 96th General Assembly, the Commission
5shall convene a workshop process during which interested
6participants may discuss issues related to the program,
7including program design, eligible electric energy efficiency
8measures, vendor qualifications, and a methodology for
9ensuring ongoing compliance with such qualifications,
10financing, sample documents such as request for proposals,
11contracts and agreements, dispute resolution, pre-installment
12and post-installment verification, and evaluation. The
13workshop process shall be completed within 150 days after the
14effective date of this amendatory Act of the 96th General
15Assembly.
16    (c) Not later than 60 days following completion of the
17workshop process described in subsection (b-5) of this Section,
18each electric utility subject to subsection (b) of this Section
19shall submit a proposed program to the Commission that contains
20the following components:
21        (1) A list of recommended electric energy efficiency
22    measures that will be eligible for on-bill financing. An
23    eligible electric energy efficiency measure ("measure")
24    shall be defined by the following:
25            (A) the measure would be applied to or replace
26        electric energy-using equipment; and either

 

 

SB1652 Enrolled- 160 -LRB097 09323 ASK 49458 b

1            (B) application of the measure to equipment and
2        systems will have estimated electricity savings
3        (determined by rates in effect at the time of
4        purchase), that are sufficient to cover the costs of
5        implementing the measures, including finance charges
6        and any program fees not recovered pursuant to
7        subsection (f) of this Section; to . To assist the
8        electric utility in identifying or approving measures,
9        the utility may consult with the Department of Commerce
10        and Economic Opportunity, as well as with retailers,
11        technicians, and installers of electric energy
12        efficiency measures and energy auditors (collectively
13        "vendors"); or .
14            (C) the measure is included in a
15        Commission-approved energy efficiency and
16        demand-response plan under Section 8-103 of this Act
17        and is cost-effective as that term is defined by that
18        Section.
19        (2) The electric utility shall issue a request for
20    proposals ("RFP") to lenders for purposes of providing
21    financing to participants to pay for approved measures. The
22    RFP criteria shall include, but not be limited to, the
23    interest rate, origination fees, and credit terms. The
24    utility shall select the winning bidders based on its
25    evaluation of these criteria, with a preference for those
26    bids containing the rates, fees, and terms most favorable

 

 

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1    to participants;
2        (3) The utility shall work with the lenders selected
3    pursuant to the RFP process, and with vendors, to establish
4    the terms and processes pursuant to which a participant can
5    purchase eligible electric energy efficiency measures
6    using the financing obtained from the lender. The vendor
7    shall explain and offer the approved financing packaging to
8    those customers identified in subsection (b) of this
9    Section and shall assist customers in applying for
10    financing. As part of the process, vendors shall also
11    provide to participants information about any other
12    incentives that may be available for the measures.
13        (4) The lender shall conduct credit checks or undertake
14    other appropriate measures to limit credit risk, and shall
15    review and approve or deny financing applications
16    submitted by customers identified in subsection (b) of this
17    Section. Following the lender's approval of financing and
18    the participant's purchase of the measure or measures, the
19    lender shall forward payment information to the electric
20    utility, and the utility shall add as a separate line item
21    on the participant's utility bill a charge showing the
22    amount due under the program each month.
23        (5) A loan issued to a participant pursuant to the
24    program shall be the sole responsibility of the
25    participant, and any dispute that may arise concerning the
26    loan's terms, conditions, or charges shall be resolved

 

 

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1    between the participant and lender. Upon transfer of the
2    property title for the premises at which the participant
3    receives electric service from the utility or the
4    participant's request to terminate service at such
5    premises, the participant shall pay in full its electric
6    utility bill, including all amounts due under the program,
7    provided that this obligation may be modified as provided
8    in subsection (g) of this Section. Amounts due under the
9    program shall be deemed amounts owed for residential and,
10    as appropriate, small commercial electric service.
11        (6) The electric utility shall remit payment in full to
12    the lender each month on behalf of the participant. In the
13    event a participant defaults on payment of its electric
14    utility bill, the electric utility shall continue to remit
15    all payments due under the program to the lender, and the
16    utility shall be entitled to recover all costs related to a
17    participant's nonpayment through the automatic adjustment
18    clause tariff established pursuant to Section 16-111.8 of
19    this Act. In addition, the electric utility shall retain a
20    security interest in the measure or measures purchased
21    under the program, and the utility retains its right to
22    disconnect a participant that defaults on the payment of
23    its utility bill.
24        (7) The total outstanding amount financed under the
25    program shall not exceed $2.5 million for an electric
26    utility or electric utilities under a single holding

 

 

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1    company, provided that the electric utility or electric
2    utilities may petition the Commission for an increase in
3    such amount.
4    (d) A program approved by the Commission shall also include
5the following criteria and guidelines for such program:
6        (1) guidelines for financing of measures installed
7    under a program, including, but not limited to, RFP
8    criteria and limits on both individual loan amounts and the
9    duration of the loans;
10        (2) criteria and standards for identifying and
11    approving measures;
12        (3) qualifications of vendors that will market or
13    install measures, as well as a methodology for ensuring
14    ongoing compliance with such qualifications;
15        (4) sample contracts and agreements necessary to
16    implement the measures and program; and
17        (5) the types of data and information that utilities
18    and vendors participating in the program shall collect for
19    purposes of preparing the reports required under
20    subsection (g) of this Section.
21    (e) The proposed program submitted by each electric utility
22shall be consistent with the provisions of this Section that
23define operational, financial and billing arrangements between
24and among program participants, vendors, lenders, and the
25electric utility.
26    (f) An electric utility shall recover all of the prudently

 

 

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1incurred costs of offering a program approved by the Commission
2pursuant to this Section, including, but not limited to, all
3start-up and administrative costs and the costs for program
4evaluation. All prudently incurred costs under this Section
5shall be recovered from the residential and small commercial
6retail customer classes eligible to participate in the program
7through the automatic adjustment clause tariff established
8pursuant to Section 8-103 of this Act.
9    (g) An independent evaluation of a program shall be
10conducted after 3 years of the program's operation. The
11electric utility shall retain an independent evaluator who
12shall evaluate the effects of the measures installed under the
13program and the overall operation of the program, including but
14not limited to customer eligibility criteria and whether the
15payment obligation for permanent electric energy efficiency
16measures that will continue to provide benefits of energy
17savings should attach to the meter location. As part of the
18evaluation process, the evaluator shall also solicit feedback
19from participants and interested stakeholders. The evaluator
20shall issue a report to the Commission on its findings no later
21than 4 years after the date on which the program commenced, and
22the Commission shall issue a report to the Governor and General
23Assembly including a summary of the information described in
24this Section as well as its recommendations as to whether the
25program should be discontinued, continued with modification or
26modifications or continued without modification, provided that

 

 

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1any recommended modifications shall only apply prospectively
2and to measures not yet installed or financed.
3    (h) An electric utility offering a Commission-approved
4program pursuant to this Section shall not be required to
5comply with any other statute, order, rule, or regulation of
6this State that may relate to the offering of such program,
7provided that nothing in this Section is intended to limit the
8electric utility's obligation to comply with this Act and the
9Commission's orders, rules, and regulations, including Part
10280 of Title 83 of the Illinois Administrative Code.
11    (i) The source of a utility customer's electric supply
12shall not disqualify a customer from participation in the
13utility's on-bill financing program. Customers of alternative
14retail electric suppliers may participate in the program under
15the same terms and conditions applicable to the utility's
16supply customers.
17(Source: P.A. 96-33, eff. 7-10-09.)
 
18    (220 ILCS 5/16-128)
19    Sec. 16-128. Provisions related to utility employees
20during the mandatory transition period.
21    (a) The General Assembly finds:
22        (1) The reliability and safety of the electric system
23    has depended and depends on a workforce of skilled and
24    dedicated employees, equipped with technical training and
25    experience.

 

 

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1        (2) The integrity and reliability of the system has
2    also requires depended on the industry's commitment to
3    invest in regular inspection and maintenance, to assure
4    that it can withstand the demands of heavy service
5    requirements and emergency situations.
6        (3) It is in the State's interest to protect the
7    interests of utility employees who have and continue to
8    dedicate dedicated themselves to assuring reliable service
9    to the citizens of this State, and who might otherwise be
10    economically displaced in a restructured industry.
11    The General Assembly further finds that it is necessary to
12assure that employees of electric utilities and employees of
13contractors or subcontractors performing work on behalf of an
14electric utility operating in the deregulated industry have the
15requisite skills, knowledge, training, experience, and
16competence to provide reliable and safe electrical service
17under this Act and therefore that alternative retail electric
18suppliers shall be required to demonstrate the competence of
19their employees to work in the industry.
20    The General Assembly also finds that it is necessary to
21assure that employees of alternative retail electric suppliers
22and employees of contractors or subcontractors performing work
23on behalf of an alternative retail electric supplier operating
24in the deregulated industry have the requisite skills,
25knowledge, training, experience, and competence to provide
26reliable and safe electrical service under this Act.

 

 

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1    To ensure that these findings and prerequisites for
2reliable and safe electrical service continue to prevail, each
3alternative retail electric supplier, electric utility, and
4contractors and subcontractors performing work on behalf of an
5electric utility or alternative retail electric supplier must
6demonstrate the competence of their respective employees to
7work on the distribution system.
8    The knowledge, skill, training, experience, and competence
9levels to be demonstrated shall be consistent with those
10generally required of or by the electric utilities in this
11State as of January 1, 2007, with respect to their employees
12and employees of contractors or subcontractors performing work
13on their behalf. Nothing in this Section shall prohibit an
14electric utility from establishing knowledge, skill, training,
15experience, and competence levels greater than those required
16as of January 1, 2007.
17    An adequate Adequate demonstration of requisite knowledge,
18skill, training, experience, and competence shall include, at a
19minimum, such factors as completion or current participation
20and ultimate completion by the employee of an accredited or
21otherwise recognized apprenticeship program for the particular
22craft, trade or skill, or specified and several years of
23employment with an electric utility performing a particular
24work function that is utilized by an electric utility.
25    Notwithstanding any law, tariff, Commission rule, order,
26or decision to the contrary, the Commission shall have an

 

 

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1affirmative statutory obligation to ensure that an electric
2utility is employing employees, contractors, and
3subcontractors with employees who meet the requirements of
4subsection (a) of this Section when installing, constructing,
5operating, and maintaining generation, transmission, or
6distribution facilities and equipment within this State
7pursuant to any provision in this Act or any Commission order,
8rule, or decision.
9    For purposes of this Section, "distribution facilities and
10equipment" means any and all of the facilities and equipment,
11including, but not limited to, substations, distribution
12feeder circuits, switches, meters, protective equipment,
13primary circuits, distribution transformers, line extensions
14and service extensions both above or below ground, conduit,
15risers, elbows, transformer pads, junction boxes, manholes,
16pedestals, conductors, and all associated fittings that
17connect the transmission or distribution system to either the
18weatherhead on the retail customer's building or other
19structure for above ground service or to the terminals on the
20meter base of the retail customer's building or other structure
21for below ground service.
22    To implement this requirement for alternative retail
23electric suppliers, the Commission, in determining that an
24applicant meets the standards for certification as an
25alternative retail electric supplier, shall require the
26applicant to demonstrate (i) that the applicant is licensed to

 

 

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1do business, and bonded, in the State of Illinois; and (ii)
2that the employees of the applicant that will be installing,
3operating, and maintaining generation, transmission, or
4distribution facilities within this State, or any entity with
5which the applicant has contracted to perform those functions
6within this State, have the requisite knowledge, skills,
7training, experience, and competence to perform those
8functions in a safe and responsible manner in order to provide
9safe and reliable service, in accordance with the criteria
10stated above.
11    (b) The General Assembly finds, based on experience in
12other industries that have undergone similar transitions, that
13the introduction of competition into the State's electric
14utility industry may result in workforce reductions by electric
15utilities which may adversely affect persons who have been
16employed by this State's electric utilities in functions
17important to the public convenience and welfare. The General
18Assembly further finds that the impacts on employees and their
19communities of any necessary reductions in the utility
20workforce directly caused by this restructuring of the electric
21industry shall be mitigated to the extent practicable through
22such means as offers of voluntary severance, retraining, early
23retirement, outplacement and related benefits. Therefore,
24before any such reduction in the workforce during the
25transition period, an electric utility shall present to its
26employees or their representatives a workforce reduction plan

 

 

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1outlining the means by which the electric utility intends to
2mitigate the impact of such workforce reduction on its
3employees.
4    (c) In the event of a sale, purchase, or any other transfer
5of ownership during the mandatory transition period of one or
6more Illinois divisions or business units, and/or generating
7stations or generating units, of an electric utility, the
8electric utility's contract and/or agreements with the
9acquiring entity or persons shall require that the entity or
10persons hire a sufficient number of non-supervisory employees
11to operate and maintain the station, division or unit by
12initially making offers of employment to the non-supervisory
13workforce of the electric utility's division, business unit,
14generating station and/or generating unit at no less than the
15wage rates, and substantially equivalent fringe benefits and
16terms and conditions of employment that are in effect at the
17time of transfer of ownership of said division, business unit,
18generating station, and/or generating units; and said wage
19rates and substantially equivalent fringe benefits and terms
20and conditions of employment shall continue for at least 30
21months from the time of said transfer of ownership unless the
22parties mutually agree to different terms and conditions of
23employment within that 30-month period. The utility shall offer
24a transition plan to those employees who are not offered jobs
25by the acquiring entity because that entity has a need for
26fewer workers. If there is litigation concerning the sale, or

 

 

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1other transfer of ownership of the electric utility's
2divisions, business units, generating station, or generating
3units, the 30-month period will begin on the date the acquiring
4entity or persons take control or management of the divisions,
5business units, generating station or generating units of the
6electric utility.
7    (d) If a utility transfers ownership during the mandatory
8transition period of one or more Illinois divisions, business
9units, generating stations or generating units of an electric
10utility to a majority-owned subsidiary, that subsidiary shall
11continue to employ the utility's employees who were employed by
12the utility at such division, business unit or generating
13station at the time of the transfer under the same terms and
14conditions of employment as those employees enjoyed at the time
15of the transfer. If ownership of the subsidiary is subsequently
16sold or transferred to a third party during the transition
17period, the transition provisions outlined in subsection (c)
18shall apply.
19    (e) The plant transfer provisions set forth above shall not
20apply to any generating station which was the subject of a
21sales agreement entered into before January 1, 1997.
22(Source: P.A. 90-561, eff. 12-16-97.)
 
23    (220 ILCS 5/16-128A new)
24    Sec. 16-128A. Certification of installers.
25    (a) Within 18 months of the effective date of this

 

 

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1amendatory Act of the 97th General Assembly, the Commission
2shall adopt rules, including emergency rules, establishing
3certification requirements ensuring that entities installing
4distributed generation facilities are in compliance with the
5requirements of subsection (a) of Section 16-128 of this Act.
6    For purposes of this Section, the phrase "entities
7installing distributed generation facilities" shall include,
8but not be limited to, all entities that are exempt from the
9definition of "alternative retail electric supplier" under
10item (v) of Section 16-102 of this Act. For purposes of this
11Section, the phrase "self-installer" means an individual who
12(i) leases or purchases a cogeneration facility for his or her
13own personal use and (ii) installs such cogeneration or
14self-generation facility on his or her own premises without the
15assistance of any other person.
16    (b) In addition to any authority granted to the Commission
17under this Act, the Commission is also authorized to: (1)
18determine which entities are subject to certification under
19this Section; (2) impose reasonable certification fees and
20penalties; (3) adopt disciplinary procedures; (4) investigate
21any and all activities subject to this Section, including
22violations thereof; (5) adopt procedures to issue or renew, or
23to refuse to issue or renew, a certification or to revoke,
24suspend, place on probation, reprimand, or otherwise
25discipline a certified entity under this Act or take other
26enforcement action against an entity subject to this Section;

 

 

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1and (6) prescribe forms to be issued for the administration and
2enforcement of this Section.
3    (c) No electric utility shall provide a retail customer
4with net metering service related to interconnection of that
5customer's distributed generation facility unless the customer
6provides the electric utility with (i) a certification that the
7customer installing the distributed generation facility was a
8self-installer or (ii) evidence that the distributed
9generation facility was installed by an entity certified under
10this Section that is also in good standing with the Commission.
11For purposes of this subsection, a retail customer includes
12that customer's employees, officers, and agents. An electric
13utility shall file a tariff or tariffs with the Commission
14setting forth the documentation that a retail customer must
15provide to an electric utility. The provisions of this
16subsection (c) shall apply on or after the effective date of
17the Commission's rules prescribed pursuant to subsection (a) of
18this Section.
19    (d) Within 180 days after the effective date of this
20amendatory Act of the 97th General Assembly, the Commission
21shall initiate a rulemaking proceeding to establish
22certification requirements that shall be applicable to vendors
23that install electric vehicle charging stations.
 
24    Section 99. Effective date. This Act takes effect upon
25becoming law.