99TH GENERAL ASSEMBLY
State of Illinois
2015 and 2016
HB2607

 

Introduced , by Rep. Elaine Nekritz

 

SYNOPSIS AS INTRODUCED:
 
See Index

    Amends the Illinois Power Agency Act. Requires the Planning and Procurement Bureau to establish a long-term renewable resources procurement plan that includes all renewable energy credits necessary to meet specified goals (replacing the current renewable portfolio standards). Sets forth guidelines for what shall be included in the procurement plan. Makes changes to provisions concerning definitions, the powers of the Agency, the Illinois Power Agency Renewable Energy Resources Fund, and the duties of the Planning and Procurement Bureau. Amends the Public Utilities Act. Makes changes concerning nondiscrimination, energy efficiency and demand-response measures, natural gas efficiency programs, real-time pricing, infrastructure investment and modernization, the Illinois Smart Grid test bed, and on-bill financing programs for electric and gas utilities. Adds provisions related to renewable energy credit procurement. Amends the Environmental Protection Act. Provides that upon promulgation by the U.S. Environmental Protection Agency of a final rule regulating carbon dioxide emissions from existing electric generating units, the Illinois Environmental Protection Agency shall be authorized to implement a cap and invest program or similar market mechanism to regulate carbon dioxide emissions. Makes other changes. Effective immediately.


LRB099 06217 AMC 30868 b

FISCAL NOTE ACT MAY APPLY

 

 

A BILL FOR

 

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1    AN ACT concerning regulation.
 
2    Be it enacted by the People of the State of Illinois,
3represented in the General Assembly:
 
4    Section 5. The Illinois Power Agency Act is amended by
5changing Sections 1-5, 1-10, 1-20, 1-56, and 1-75 as follows:
 
6    (20 ILCS 3855/1-5)
7    Sec. 1-5. Legislative declarations and findings. The
8General Assembly finds and declares:
9        (1) The health, welfare, and prosperity of all Illinois
10    citizens require the provision of adequate, reliable,
11    affordable, efficient, and environmentally sustainable
12    electric service at the lowest total cost over time, taking
13    into account any benefits of price stability.
14        (2) The transition to retail competition is not
15    complete. Some customers, especially residential and small
16    commercial customers, have failed to benefit from lower
17    electricity costs from retail and wholesale competition.
18        (3) Escalating prices for electricity in Illinois pose
19    a serious threat to the economic well-being, health, and
20    safety of the residents of and the commerce and industry of
21    the State.
22        (4) To protect against this threat to economic
23    well-being, health, and safety it is necessary to improve

 

 

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1    the process of procuring electricity to serve Illinois
2    residents, to promote investment in energy efficiency and
3    demand-response measures, and to support development of
4    clean coal technologies and renewable resources.
5        (5) Procuring a diverse electricity supply portfolio
6    will ensure the lowest total cost over time for adequate,
7    reliable, efficient, and environmentally sustainable
8    electric service.
9        (6) Including cost-effective renewable resources in
10    that portfolio will reduce long-term direct and indirect
11    costs to consumers by decreasing environmental impacts and
12    by avoiding or delaying the need for new generation,
13    transmission, and distribution infrastructure.
14        (7) Energy efficiency, demand-response measures, and
15    renewable energy are resources currently underused in
16    Illinois. These and other demand-side resources should be
17    used when cost-effective to reduce costs to consumers and
18    encourage job creation.
19        (8) The State should encourage the use of advanced
20    clean coal technologies that capture and sequester carbon
21    dioxide emissions to advance environmental protection
22    goals and to demonstrate the viability of coal and
23    coal-derived fuels in a carbon-constrained economy.
24        (9) The General Assembly enacted Public Act 96-0795 to
25    reform the State's purchasing processes, recognizing that
26    government procurement is susceptible to abuse if

 

 

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1    structural and procedural safeguards are not in place to
2    ensure independence, insulation, oversight, and
3    transparency.
4        (10) The principles that underlie the procurement
5    reform legislation apply also in the context of power
6    purchasing.
7    The General Assembly therefore finds that it is necessary
8to create the Illinois Power Agency and that the goals and
9objectives of that Agency are to accomplish each of the
10following:
11        (A) Develop electricity procurement plans to ensure
12    adequate, reliable, affordable, efficient, and
13    environmentally sustainable electric service at the lowest
14    total cost over time, taking into account any benefits of
15    price stability, for electric utilities that on December
16    31, 2005 provided electric service to at least 100,000
17    customers in Illinois and for small multi-jurisdictional
18    electric utilities that (i) on December 31, 2005 served
19    less than 100,000 customers in Illinois and (ii) request a
20    procurement plan for their Illinois jurisdictional load.
21    The procurement plan shall be updated on an annual basis
22    and shall include renewable energy resources sufficient to
23    achieve the standards specified in this Act.
24        (B) Conduct competitive procurement processes to
25    procure the supply resources identified in the procurement
26    plan.

 

 

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1        (C) Develop electric generation and co-generation
2    facilities that use indigenous coal or renewable
3    resources, or both, financed with bonds issued by the
4    Illinois Finance Authority.
5        (D) Supply electricity from the Agency's facilities at
6    cost to one or more of the following: municipal electric
7    systems, governmental aggregators, or rural electric
8    cooperatives in Illinois.
9        (E) Ensure that the process of power procurement is
10    conducted in an ethical and transparent fashion, immune
11    from improper influence.
12        (F) Continue to review its policies and practices to
13    determine how best to meet its mission of providing the
14    lowest cost power to the greatest number of people, at any
15    given point in time, in accordance with applicable law.
16        (G) Operate in a structurally insulated, independent,
17    and transparent fashion so that nothing impedes the
18    Agency's mission to secure power at the best prices the
19    market will bear, provided that the Agency meets all
20    applicable legal requirements.
21(Source: P.A. 97-325, eff. 8-12-11; 97-618, eff. 10-26-11;
2297-813, eff. 7-13-12.)
 
23    (20 ILCS 3855/1-10)
24    Sec. 1-10. Definitions.
25    "Agency" means the Illinois Power Agency.

 

 

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

 

 

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

 

 

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1million btu content, unless the clean coal facility does not
2use gasification technology and was operating as a conventional
3coal-fired electric generating facility on June 1, 2009 (the
4effective date of Public Act 95-1027).
5    "Clean coal SNG brownfield facility" means a facility that
6(1) has commenced construction by July 1, 2015 on an urban
7brownfield site in a municipality with at least 1,000,000
8residents; (2) uses a gasification process to produce
9substitute natural gas; (3) uses coal as at least 50% of the
10total feedstock over the term of any sourcing agreement with a
11utility and the remainder of the feedstock may be either
12petroleum coke or coal, with all such coal having a high
13bituminous rank and greater than 1.7 pounds of sulfur per
14million Btu content unless the facility reasonably determines
15that it is necessary to use additional petroleum coke to
16deliver additional consumer savings, in which case the facility
17shall use coal for at least 35% of the total feedstock over the
18term of any sourcing agreement; and (4) captures and sequesters
19at least 85% of the total carbon dioxide emissions that the
20facility would otherwise emit.
21    "Clean coal SNG facility" means a facility that uses a
22gasification process to produce substitute natural gas, that
23sequesters at least 90% of the total carbon dioxide emissions
24that the facility would otherwise emit, that uses at least 90%
25coal as a feedstock, with all such coal having a high
26bituminous rank and greater than 1.7 pounds of sulfur per

 

 

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1million btu content, and that has a valid and effective permit
2to construct emission sources and air pollution control
3equipment and approval with respect to the federal regulations
4for Prevention of Significant Deterioration of Air Quality
5(PSD) for the plant pursuant to the federal Clean Air Act;
6provided, however, a clean coal SNG brownfield facility shall
7not be a clean coal SNG facility.
8    "Commission" means the Illinois Commerce Commission.
9    "Community solar project" means an electric generating
10facility that:
11        (1) generates electricity using photovoltaic cells;
12        (2) is interconnected at the distribution system level
13    of an electric utility as defined in this Section;
14        (3) credits the value of electricity generated by the
15    facility to the subscribers of the facility; and
16        (4) is limited in nameplate capacity to no more than
17    2,000 kilowatts.
18    "Costs incurred in connection with the development and
19construction of a facility" means:
20        (1) the cost of acquisition of all real property,
21    fixtures, and improvements in connection therewith and
22    equipment, personal property, and other property, rights,
23    and easements acquired that are deemed necessary for the
24    operation and maintenance of the facility;
25        (2) financing costs with respect to bonds, notes, and
26    other evidences of indebtedness of the Agency;

 

 

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

 

 

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

 

 

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

 

 

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

 

 

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1indebtedness issued by the Authority, the principal and
2interest of which is payable solely from revenues or income
3derived from any project or activity of the Agency.
4    "Sequester" means permanent storage of carbon dioxide by
5injecting it into a saline aquifer, a depleted gas reservoir,
6or an oil reservoir, directly or through an enhanced oil
7recovery process that may involve intermediate storage,
8regardless of whether these activities are conducted by a clean
9coal facility, a clean coal SNG facility, a clean coal SNG
10brownfield facility, or a party with which a clean coal
11facility, clean coal SNG facility, or clean coal SNG brownfield
12facility has contracted for such purposes.
13    "Service area" has the same definition as found in Section
1416-102 of the Public Utilities Act.
15    "Sourcing agreement" means (i) in the case of an electric
16utility, an agreement between the owner of a clean coal
17facility and such electric utility, which agreement shall have
18terms and conditions meeting the requirements of paragraph (3)
19of subsection (d) of Section 1-75, (ii) in the case of an
20alternative retail electric supplier, an agreement between the
21owner of a clean coal facility and such alternative retail
22electric supplier, which agreement shall have terms and
23conditions meeting the requirements of Section 16-115(d)(5) of
24the Public Utilities Act, and (iii) in case of a gas utility,
25an agreement between the owner of a clean coal SNG brownfield
26facility and the gas utility, which agreement shall have the

 

 

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1terms and conditions meeting the requirements of subsection
2(h-1) of Section 9-220 of the Public Utilities Act.
3    "Standard wholesale product" means any type of product that
4is routinely traded in a liquid regional wholesale market,
5including, but not limited to, energy or demand-side resources.
6    "Subscriber" means any customer that takes delivery
7service from an electric utility who owns one or more
8subscriptions to a community solar project and who has
9identified an individual billing meter within the same electric
10utility service territory as the community solar project is
11located to which each subscription shall be attributed. Each
12subscriber to a single community solar project must have a
13separate legal or corporate identity, and no subscriber's
14subscriptions may total more than 40% of an individual
15community solar project.
16    "Subscription" means a percentage interest in a community
17solar project. Each subscription shall represent a percentage
18of the community solar project's generating capacity, provided
19that the subscription is intended to primarily offset part or
20all of the subscriber's electricity usage.
21    "Substitute natural gas" or "SNG" means a gas manufactured
22by gasification of hydrocarbon feedstock, which is
23substantially interchangeable in use and distribution with
24conventional natural gas.
25    "Total resource cost test" or "TRC test" means a standard
26that is met if, for an investment in energy efficiency or

 

 

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1demand-response measures, the benefit-cost ratio is greater
2than one. The benefit-cost ratio is the ratio of the net
3present value of the total benefits of the program to the net
4present value of the total costs as calculated over the
5lifetime of the measures. A total resource cost test compares
6the sum of avoided electric utility costs, representing the
7benefits that accrue to the system and the participant in the
8delivery of those efficiency measures, including avoided
9energy costs, avoided generating capacity costs, avoided
10transmission and distribution system investments and price
11suppression effects, as well as other quantifiable societal
12benefits, including avoided natural gas utility costs, other
13avoided energy costs, and reasonable estimates of non-energy
14benefits, such as the health, safety, comfort, operation and
15maintenance, business productivity, and financial security
16benefits to low-income and moderate-income customers of
17efficiency investments, to the sum of all incremental costs of
18end-use measures that are implemented due to the program
19(including both utility and participant contributions), plus
20costs to administer, deliver, and evaluate each demand-side
21program, to quantify the net savings obtained by substituting
22the demand-side program for supply resources. In calculating
23avoided costs of power and energy that an electric utility
24would otherwise have had to acquire, reasonable estimates shall
25be included of financial costs likely to be imposed by future
26regulations and legislation on emissions of greenhouse gases.

 

 

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1In discounting future costs and benefits for the purpose of
2computing net present values, a societal discount rate based on
3real, long-term Treasury bond yields or other appropriate
4indictors should be used.
5(Source: P.A. 97-96, eff. 7-13-11; 97-239, eff. 8-2-11; 97-491,
6eff. 8-22-11; 97-616, eff. 10-26-11; 97-813, eff. 7-13-12;
798-90, eff. 7-15-13.)
 
8    (20 ILCS 3855/1-20)
9    Sec. 1-20. General powers of the Agency.
10    (a) The Agency is authorized to do each of the following:
11        (1) Develop electricity procurement plans to ensure
12    adequate, reliable, affordable, efficient, and
13    environmentally sustainable electric service at the lowest
14    total cost over time, taking into account any benefits of
15    price stability, for electric utilities that on December
16    31, 2005 provided electric service to at least 100,000
17    customers in Illinois and for small multi-jurisdictional
18    electric utilities that (A) on December 31, 2005 served
19    less than 100,000 customers in Illinois and (B) request a
20    procurement plan for their Illinois jurisdictional load.
21    The electricity procurement plans shall be updated on an
22    annual basis and shall, until May 31, 2016, include
23    electricity generated from renewable resources sufficient
24    to achieve the standards specified in this Act and shall
25    include energy efficiency and demand response resources

 

 

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1    identified under Sections 16-108.5, 16-111.5, and
2    16-111.5B of the Public Utilities Act.
3        (1.5) Beginning with the planning process for the plan
4    or plans to be implemented in the 2016 delivery year,
5    develop a long-term renewable resources procurement plan
6    in accordance with subdivision (c) of Section 1-75 of this
7    Act for renewable energy credits in amounts sufficient to
8    achieve the standards specified in this Act for all
9    customers taking delivery service from an electric
10    utility.
11        (2) Conduct competitive procurement processes to
12    procure the supply resources identified in the electricity
13    procurement plan, pursuant to Section 16-111.5 of the
14    Public Utilities Act.
15        Beginning with the 2016 delivery year, conduct
16    competitive procurement processes and implement programs
17    to procure renewable energy credits identified in the
18    long-term renewable resources procurement plan developed
19    pursuant to subdivision (c) of Section 1-75 of this Act and
20    procured pursuant to Section 16-111.5C of the Public
21    Utilities Act.
22        (3) Develop electric generation and co-generation
23    facilities that use indigenous coal or renewable
24    resources, or both, financed with bonds issued by the
25    Illinois Finance Authority.
26        (4) Supply electricity from the Agency's facilities at

 

 

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1    cost to one or more of the following: municipal electric
2    systems, governmental aggregators, or rural electric
3    cooperatives in Illinois.
4    (b) Except as otherwise limited by this Act, the Agency has
5all of the powers necessary or convenient to carry out the
6purposes and provisions of this Act, including without
7limitation, each of the following:
8        (1) To have a corporate seal, and to alter that seal at
9    pleasure, and to use it by causing it or a facsimile to be
10    affixed or impressed or reproduced in any other manner.
11        (2) To use the services of the Illinois Finance
12    Authority necessary to carry out the Agency's purposes.
13        (3) To negotiate and enter into loan agreements and
14    other agreements with the Illinois Finance Authority.
15        (4) To obtain and employ personnel and hire consultants
16    that are necessary to fulfill the Agency's purposes, and to
17    make expenditures for that purpose within the
18    appropriations for that purpose.
19        (5) To purchase, receive, take by grant, gift, devise,
20    bequest, or otherwise, lease, or otherwise acquire, own,
21    hold, improve, employ, use, and otherwise deal in and with,
22    real or personal property whether tangible or intangible,
23    or any interest therein, within the State.
24        (6) To acquire real or personal property, whether
25    tangible or intangible, including without limitation
26    property rights, interests in property, franchises,

 

 

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1    obligations, contracts, and debt and equity securities,
2    and to do so by the exercise of the power of eminent domain
3    in accordance with Section 1-21; except that any real
4    property acquired by the exercise of the power of eminent
5    domain must be located within the State.
6        (7) To sell, convey, lease, exchange, transfer,
7    abandon, or otherwise dispose of, or mortgage, pledge, or
8    create a security interest in, any of its assets,
9    properties, or any interest therein, wherever situated.
10        (8) To purchase, take, receive, subscribe for, or
11    otherwise acquire, hold, make a tender offer for, vote,
12    employ, sell, lend, lease, exchange, transfer, or
13    otherwise dispose of, mortgage, pledge, or grant a security
14    interest in, use, and otherwise deal in and with, bonds and
15    other obligations, shares, or other securities (or
16    interests therein) issued by others, whether engaged in a
17    similar or different business or activity.
18        (9) To make and execute agreements, contracts, and
19    other instruments necessary or convenient in the exercise
20    of the powers and functions of the Agency under this Act,
21    including contracts with any person, including personal
22    service contracts, or with any local government, State
23    agency, or other entity; and all State agencies and all
24    local governments are authorized to enter into and do all
25    things necessary to perform any such agreement, contract,
26    or other instrument with the Agency. No such agreement,

 

 

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1    contract, or other instrument shall exceed 40 years.
2        (10) To lend money, invest and reinvest its funds in
3    accordance with the Public Funds Investment Act, and take
4    and hold real and personal property as security for the
5    payment of funds loaned or invested.
6        (11) To borrow money at such rate or rates of interest
7    as the Agency may determine, issue its notes, bonds, or
8    other obligations to evidence that indebtedness, and
9    secure any of its obligations by mortgage or pledge of its
10    real or personal property, machinery, equipment,
11    structures, fixtures, inventories, revenues, grants, and
12    other funds as provided or any interest therein, wherever
13    situated.
14        (12) To enter into agreements with the Illinois Finance
15    Authority to issue bonds whether or not the income
16    therefrom is exempt from federal taxation.
17        (13) To procure insurance against any loss in
18    connection with its properties or operations in such amount
19    or amounts and from such insurers, including the federal
20    government, as it may deem necessary or desirable, and to
21    pay any premiums therefor.
22        (14) To negotiate and enter into agreements with
23    trustees or receivers appointed by United States
24    bankruptcy courts or federal district courts or in other
25    proceedings involving adjustment of debts and authorize
26    proceedings involving adjustment of debts and authorize

 

 

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1    legal counsel for the Agency to appear in any such
2    proceedings.
3        (15) To file a petition under Chapter 9 of Title 11 of
4    the United States Bankruptcy Code or take other similar
5    action for the adjustment of its debts.
6        (16) To enter into management agreements for the
7    operation of any of the property or facilities owned by the
8    Agency.
9        (17) To enter into an agreement to transfer and to
10    transfer any land, facilities, fixtures, or equipment of
11    the Agency to one or more municipal electric systems,
12    governmental aggregators, or rural electric agencies or
13    cooperatives, for such consideration and upon such terms as
14    the Agency may determine to be in the best interest of the
15    citizens of Illinois.
16        (18) To enter upon any lands and within any building
17    whenever in its judgment it may be necessary for the
18    purpose of making surveys and examinations to accomplish
19    any purpose authorized by this Act.
20        (19) To maintain an office or offices at such place or
21    places in the State as it may determine.
22        (20) To request information, and to make any inquiry,
23    investigation, survey, or study that the Agency may deem
24    necessary to enable it effectively to carry out the
25    provisions of this Act.
26        (21) To accept and expend appropriations.

 

 

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1        (22) To engage in any activity or operation that is
2    incidental to and in furtherance of efficient operation to
3    accomplish the Agency's purposes, including hiring
4    employees that the Director deems essential for the
5    operations of the Agency.
6        (23) To adopt, revise, amend, and repeal rules with
7    respect to its operations, properties, and facilities as
8    may be necessary or convenient to carry out the purposes of
9    this Act, subject to the provisions of the Illinois
10    Administrative Procedure Act and Sections 1-22 and 1-35 of
11    this Act.
12        (24) To establish and collect charges and fees as
13    described in this Act.
14        (25) To conduct competitive gasification feedstock
15    procurement processes to procure the feedstocks for the
16    clean coal SNG brownfield facility in accordance with the
17    requirements of Section 1-78 of this Act.
18        (26) To review, revise, and approve sourcing
19    agreements and mediate and resolve disputes between gas
20    utilities and the clean coal SNG brownfield facility
21    pursuant to subsection (h-1) of Section 9-220 of the Public
22    Utilities Act or to fulfill its responsibilities for
23    developing energy efficiency potential studies as required
24    under subsection (f) of Section 8-103 of the Public
25    Utilities Act.
26(Source: P.A. 96-784, eff. 8-28-09; 96-1000, eff. 7-2-10;

 

 

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197-96, eff. 7-13-11; 97-325, eff. 8-12-11; 97-618, eff.
210-26-11; 97-813, eff. 7-13-12.)
 
3    (20 ILCS 3855/1-56)
4    Sec. 1-56. Illinois Power Agency Renewable Energy
5Resources Fund.
6    (a) The Illinois Power Agency Renewable Energy Resources
7Fund is created as a special fund in the State treasury.
8    (b) The Illinois Power Agency Renewable Energy Resources
9Fund shall be administered by the Agency for the following
10purposes:
11        (1) to purchase renewable energy credits according to
12    any approved procurement plan developed by the Agency prior
13    to June 1, 2016; and
14        (2) to purchase renewable energy credits and pay for
15    other applicable expenses as part of a low-income solar
16    program; the Agency shall create a low-income solar program
17    with the objective of bringing solar photovoltaics to
18    low-income communities in a manner that maximizes the
19    development of new renewable energy generating facilities,
20    provides workforce development opportunities within
21    low-income communities, creates a long-term, low-income
22    solar marketplace throughout Illinois, and minimizes
23    administrative costs; the Agency shall include the
24    low-income solar program as part of the long-term renewable
25    resources procurement plan authorized by subdivision (c)

 

 

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1    of Section 1-75 of this Act, and the program shall be
2    designed to grow the low-income solar market over at least
3    10 years; for this program, the Agency shall purchase
4    renewable energy credits from either (i) photovoltaic
5    distributed renewable energy generation devices or (ii)
6    community solar projects. The electricity generated by
7    each distributed generation device or community solar
8    project must primarily be used to offset the electricity
9    usage of (i) lower-income households, (ii) properties
10    where the majority of occupants are lower-income
11    households, (iii) public sector buildings that primarily
12    serve lower-income households, or (iv) not-for-profit
13    corporations that primarily serve lower-income households.
14    As used in this subsection (b), "lower-income households"
15means persons and families whose income does not exceed 80% of
16area median income, adjusted for family size and revised every
175 years.
18    Administrative costs associated with the low-income solar
19program, including, but not limited to, the Agency's general
20administrative expenses associated with developing and
21operating the program, costs associated with the program
22manager referenced in this Section, and costs related to the
23evaluation of the low-income solar program, may be paid for
24using the Illinois Power Agency Renewable Energy Resources
25Fund, but the Agency and program manager shall strive to
26minimize administrative expenses in the implementation of the

 

 

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1program.
2    The Agency shall purchase renewable energy credits through
3an upfront payment per kilowatt of installed nameplate capacity
4paid once the device is energized. The payment shall be in
5exchange for an assignment of all renewable energy credits
6generated by the system during the first 15 years of operation
7and shall be structured to overcome barriers to participation
8in the solar market by the low-income community. The Agency
9shall retire any renewable energy credits purchased from this
10program and shall use the renewable energy credits to reduce
11the obligation under subdivision (c) of Section 1-75 of this
12Act for the electric utility to which the project is
13interconnected.
14    The Agency shall establish the low-income solar program
15terms, conditions, and requirements, including the initial
16purchase price of renewable energy credits, through the
17development, review, and approval of the Agency's long-term
18renewable resources procurement plan described in subdivision
19(c) of Section 1-75 of this Act. The Agency may review and
20adjust the program terms, conditions, and requirements,
21including the price offered to new systems, to ensure the
22long-term viability and success of the program. The Commission
23shall review and approve any modifications to the program
24through the periodic plan revision process described in Section
2516-111.5C of the Public Utilities Act.
26    The Agency shall issue a request for qualifications for a

 

 

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1third-party program manager to administer the low-income solar
2program. The third-party program manager may be a government
3entity or a not-for-profit corporation and shall be chosen
4through a competitive bid process based on selection criteria
5and requirements developed by the Agency. In selecting a
6program manager, the Agency shall consider a bidder's
7experience in (i) administering low-income energy programs
8with evidence of strong consumer protection, (ii) providing
9low-income job training opportunities, and (iii) providing or
10overseeing solar installation or energy efficiency services.
11At least every 2 years, the Commission shall select an
12independent evaluator to review and report on the low-income
13solar program and the performance of the third-party program
14manager of the low-income solar program. The report shall
15include the number of projects installed, the total installed
16capacity in kilowatts, the average cost per kilowatt of
17installed capacity, the total number of jobs or job training
18opportunities, and other economic, social and environmental
19benefits created, and the total administrative costs expended
20by the Agency and program manager to implement and evaluate the
21program. The report shall be delivered to the Commission and
22posted on the Agency's website and used, as needed, to revise
23the low-income solar program.
24    The low-income solar program manager shall administer the
25low-income solar program, which shall include the development
26of standard contract forms, the development and implementation

 

 

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1of a marketing and outreach program for eligible low-income
2customers, and providing solar installation services,
3including subcontractor solicitations when necessary. The
4low-income solar program shall also include energy efficiency
5referral and education services, solar job training and
6workforce development opportunities, and consumer protection
7provisions.
8    (b-5) Upon the submission of all payments required by
9Section 16-115D of the Public Utilities Act, no funds shall be
10deposited into the Illinois Power Agency Renewable Energy
11Resources Fund unless directed by order of the Commission.
12    (b-10) Upon the balance of the Illinois Power Agency
13Renewable Energy Resources Fund falling below $5,000, the Fund
14shall be terminated, and any remaining funds shall be
15transferred to the Low Income Home Energy Assistance Program,
16as authorized by the Energy Assistance Act.
17to procure renewable energy resources. Prior to June 1, 2011,
18resources procured pursuant to this Section shall be procured
19from facilities located in Illinois, provided the resources are
20available from those facilities. If resources are not available
21in Illinois, then they shall be procured in states that adjoin
22Illinois. If resources are not available in Illinois or in
23states that adjoin Illinois, then they may be purchased
24elsewhere. Beginning June 1, 2011, resources procured pursuant
25to this Section shall be procured from facilities located in
26Illinois or states that adjoin Illinois. If resources are not

 

 

HB2607- 28 -LRB099 06217 AMC 30868 b

1available in Illinois or in states that adjoin Illinois, then
2they may be procured elsewhere. To the extent available, at
3least 75% of these renewable energy resources shall come from
4wind generation. Of the renewable energy resources procured
5pursuant to this Section at least the following specified
6percentages shall come from photovoltaics on the following
7schedule: 0.5% by June 1, 2012; 1.5% by June 1, 2013; 3% by
8June 1, 2014; and 6% by June 1, 2015 and thereafter. Of the
9renewable energy resources procured pursuant to this Section,
10at least the following percentages shall come from distributed
11renewable energy generation devices: 0.5% by June 1, 2013,
120.75% by June 1, 2014, and 1% by June 1, 2015 and thereafter.
13To the extent available, half of the renewable energy resources
14procured from distributed renewable energy generation shall
15come from devices of less than 25 kilowatts in nameplate
16capacity. Renewable energy resources procured from distributed
17generation devices may also count towards the required
18percentages for wind and solar photovoltaics. Procurement of
19renewable energy resources from distributed renewable energy
20generation devices shall be done on an annual basis through
21multi-year contracts of no less than 5 years, and shall consist
22solely of renewable energy credits.
23    The Agency shall create credit requirements for suppliers
24of distributed renewable energy. In order to minimize the
25administrative burden on contracting entities, the Agency
26shall solicit the use of third-party organizations to aggregate

 

 

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1distributed renewable energy into groups of no less than one
2megawatt in installed capacity. These third-party
3organizations shall administer contracts with individual
4distributed renewable energy generation device owners. An
5individual distributed renewable energy generation device
6owner shall have the ability to measure the output of his or
7her distributed renewable energy generation device.
8    (c) (Blank). The Agency shall procure renewable energy
9resources at least once each year in conjunction with a
10procurement event for electric utilities required to comply
11with Section 1-75 of the Act and shall, whenever possible,
12enter into long-term contracts on an annual basis for a portion
13of the incremental requirement for the given procurement year.
14    (d) (Blank). The price paid to procure renewable energy
15credits using monies from the Illinois Power Agency Renewable
16Energy Resources Fund shall not exceed the winning bid prices
17paid for like resources procured for electric utilities
18required to comply with Section 1-75 of this Act.
19    (e) All renewable energy credits procured using monies from
20the Illinois Power Agency Renewable Energy Resources Fund shall
21be permanently retired.
22    (f) The selection of the third-party program manager, the
23selection of the independent evaluator, and the procurement
24process described in this Section are exempt from the
25requirements of Section 20-10 of the Illinois Procurement Code.
26The procurement process described in this Section is exempt

 

 

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

 

 

HB2607- 31 -LRB099 06217 AMC 30868 b

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

 

 

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

 

 

HB2607- 33 -LRB099 06217 AMC 30868 b

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

 

 

HB2607- 34 -LRB099 06217 AMC 30868 b

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

 

 

HB2607- 35 -LRB099 06217 AMC 30868 b

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

 

 

HB2607- 36 -LRB099 06217 AMC 30868 b

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

 

 

HB2607- 37 -LRB099 06217 AMC 30868 b

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

 

 

HB2607- 38 -LRB099 06217 AMC 30868 b

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

 

 

HB2607- 39 -LRB099 06217 AMC 30868 b

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

 

 

HB2607- 40 -LRB099 06217 AMC 30868 b

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

 

 

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

 

 

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1    supplemental procurement process.
2(Source: P.A. 97-616, eff. 10-26-11; 98-672, eff. 6-30-14.)
 
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 year,
8beginning in 2008, develop procurement plans and conduct
9competitive procurement processes in accordance with the
10requirements of Section 16-111.5 of the Public Utilities Act
11for the eligible retail customers of electric utilities that on
12December 31, 2005 provided electric service to at least 100,000
13customers in Illinois. The Planning and Procurement Bureau
14shall also develop procurement plans and conduct competitive
15procurement processes in accordance with the requirements of
16Section 16-111.5 of the Public Utilities Act for the eligible
17retail customers of small multi-jurisdictional electric
18utilities that (i) on December 31, 2005 served less than
19100,000 customers in Illinois and (ii) request a procurement
20plan for their Illinois jurisdictional load. This Section shall
21not apply to a small multi-jurisdictional utility until such
22time as a small multi-jurisdictional utility requests the
23Agency to prepare a procurement plan for their Illinois
24jurisdictional load. For the purposes of this Section, the term
25"eligible retail customers" has the same definition as found in

 

 

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1Section 16-111.5(a) of the Public Utilities Act.
2    Notwithstanding the requirements of this subdivision (a),
3beginning with the planning process for the plan or plans to be
4implemented in the 2016 delivery year, the Agency shall no
5longer include the procurement of renewable energy resources in
6the procurement plans required by this subdivision (a) and
7shall instead develop a long-term renewable resources
8procurement plan in accordance with subdivision (c) of this
9Section.
10        (1) The Agency shall each year, beginning in 2008, as
11    needed, issue a request for qualifications for experts or
12    expert consulting firms to develop the procurement plans in
13    accordance with Section 16-111.5 of the Public Utilities
14    Act. In order to qualify an expert or expert consulting
15    firm must have:
16            (A) direct previous experience assembling
17        large-scale power supply plans or portfolios for
18        end-use customers;
19            (B) an advanced degree in economics, mathematics,
20        engineering, risk management, or a related area of
21        study;
22            (C) 10 years of experience in the electricity
23        sector, including managing supply risk;
24            (D) expertise in wholesale electricity market
25        rules, including those established by the Federal
26        Energy Regulatory Commission and regional transmission

 

 

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

 

 

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1        required functions and responsibilities; and
2            (G) the absence of a conflict of interest and
3        inappropriate bias for or against potential bidders or
4        the affected electric utilities.
5        (3) The Agency shall provide affected utilities and
6    other interested parties with the lists of qualified
7    experts or expert consulting firms identified through the
8    request for qualifications processes that are under
9    consideration to develop the procurement plans and to serve
10    as the procurement administrator. The Agency shall also
11    provide each qualified expert's or expert consulting
12    firm's response to the request for qualifications. All
13    information provided under this subparagraph shall also be
14    provided to the Commission. The Agency may provide by rule
15    for fees associated with supplying the information to
16    utilities and other interested parties. These parties
17    shall, within 5 business days, notify the Agency in writing
18    if they object to any experts or expert consulting firms on
19    the lists. Objections shall be based on:
20            (A) failure to satisfy qualification criteria;
21            (B) identification of a conflict of interest; or
22            (C) evidence of inappropriate bias for or against
23        potential bidders or the affected utilities.
24        The Agency shall remove experts or expert consulting
25    firms from the lists within 10 days if there is a
26    reasonable basis for an objection and provide the updated

 

 

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1    lists to the affected utilities and other interested
2    parties. If the Agency fails to remove an expert or expert
3    consulting firm from a list, an objecting party may seek
4    review by the Commission within 5 days thereafter by filing
5    a petition, and the Commission shall render a ruling on the
6    petition within 10 days. There is no right of appeal of the
7    Commission's ruling.
8        (4) The Agency shall issue requests for proposals to
9    the qualified experts or expert consulting firms to develop
10    a procurement plan for the affected utilities and to serve
11    as procurement administrator.
12        (5) The Agency shall select an expert or expert
13    consulting firm to develop procurement plans based on the
14    proposals submitted and shall award contracts of up to 5
15    years to those selected.
16        (6) The Agency shall select an expert or expert
17    consulting firm, with approval of the Commission, to serve
18    as procurement administrator based on the proposals
19    submitted. If the Commission rejects, within 5 days, the
20    Agency's selection, the Agency shall submit another
21    recommendation within 3 days based on the proposals
22    submitted. The Agency shall award a 5-year contract to the
23    expert or expert consulting firm so selected with
24    Commission approval.
25    (b) The experts or expert consulting firms retained by the
26Agency shall, as appropriate, prepare procurement plans, and

 

 

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1conduct a competitive procurement process as prescribed in
2Section 16-111.5 of the Public Utilities Act, to ensure
3adequate, reliable, affordable, efficient, and environmentally
4sustainable electric service at the lowest total cost over
5time, taking into account any benefits of price stability, for
6eligible retail customers of electric utilities that on
7December 31, 2005 provided electric service to at least 100,000
8customers in the State of Illinois, and for eligible Illinois
9retail customers of small multi-jurisdictional electric
10utilities that (i) on December 31, 2005 served less than
11100,000 customers in Illinois and (ii) request a procurement
12plan for their Illinois jurisdictional load.
13    (c) Renewable portfolio standard.
14        (1) The Planning and Procurement Bureau shall develop a
15    long-term renewable resources procurement plan that
16    includes all renewable energy credits necessary to meet the
17    goals set forth in this subdivision (c). The long-term
18    renewable resources procurement plan shall include
19    long-term programs and competitive procurement events
20    designed to meet the renewable resources goals in this
21    subdivision (c) from the date of the plan through the 2030
22    delivery year. The initial long-term renewable resources
23    procurement plan shall be released for comment no later
24    than 120 days after the effective date of this amendatory
25    Act of the 99th General Assembly. The Agency shall review
26    and revise the long-term renewable resources procurement

 

 

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1    plan at least every 2 years. The initial long-term
2    renewable resources procurement plan and each revised plan
3    shall be subject to review and approval by the Commission
4    pursuant to Section 16-111.5C of the Public Utilities Act.
5        (1.5) The Agency shall continue to implement all
6    procurements of renewable energy credits included in all
7    prior procurement plans filed with the Commission prior to
8    June 1, 2016. Any renewable energy credits procured as a
9    result of these prior procurements, including renewable
10    energy credits as part of bundled renewable energy
11    resources, shall be used to meet the goals set forth in
12    this subdivision (c) and shall be included as resources in
13    the long-term renewable resources plan required in
14    paragraph (1) of this subdivision (c). Any costs associated
15    with the procurement of renewable energy credits as a
16    result of these prior procurements, including the cost of
17    renewable energy credits included in the cost of bundled
18    renewable energy resources, but not including any
19    renewable energy credits procured as a result of
20    procurements authorized by subsection (i) of Section 1-56
21    of this Act or paid for using funds collected as a result
22    of paragraph (5) of this subdivision (c), shall be included
23    in the total cost of renewable energy credits procured
24    pursuant to the long-term procurement plan, as limited in
25    paragraph (1.15) of this subdivision (c).
26        As used in this subdivision (c):

 

 

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1        "Bundled renewable energy resources" means electricity
2    generated by a renewable energy system and its associated
3    renewable energy credit.
4        "Cost of renewable energy credits included in the cost
5    of bundled renewable energy resources" means the
6    difference between the contract price for the bundled
7    renewable energy resources and the day-ahead locational
8    marginal price at the load zone at which the contract is
9    settled multiplied by the megawatt hours of electricity
10    generated in each hour.
11        (1.10) The cost of any renewable energy credits
12    procured through a competitive procurement event pursuant
13    to an approved plan shall not exceed benchmarks established
14    by the procurement administrator, in consultation with the
15    Commission staff, Agency staff, and the procurement
16    monitor. The benchmarks shall be based on price data for
17    similar products for the same delivery period and same
18    utility delivery hub or other utility delivery hubs after
19    adjusting for that difference. The price benchmarks may
20    also be adjusted to take into account differences between
21    the information reflected in the underlying data sources
22    and the specific products and procurement process being
23    used to procure power for the Illinois utilities. The
24    benchmarks shall be confidential, but shall be provided to
25    the Commission and shall be subject to Commission review
26    and approval prior to a procurement event.

 

 

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1        (1.15) Notwithstanding the requirements of this
2    subdivision (c), the total amount of renewable energy
3    credits procured pursuant to the long-term renewable
4    resources procurement plan shall be reduced by an amount
5    necessary to limit the annual estimated average net
6    increase due to the costs of these credits included in the
7    amounts paid by all customers taking delivery service from
8    an electric utility to no more than 2.015% of the amount
9    paid per kilowatthour by eligible retail customers during
10    the year ending May 31, 2007. For purposes of this
11    subdivision (c), the amount paid per kilowatthour means the
12    total amount paid for electric service expressed on a per
13    kilowatthour basis, including without limitation amounts
14    paid for supply, transmission, distribution, surcharges,
15    and add-on taxes.
16        (1.20) The long-term renewable resources procurement
17    plan shall include the procurement of renewable energy
18    credits in amounts equal to at least the following
19    percentages measured as a percentage of the projected
20    amount of electricity in kilowatthours to be delivered by
21    the electric utilities to all customers taking delivery
22    service from an electric utility: 11.5% by the 2016
23    delivery year, and increasing by at least 1.5% each
24    delivery year thereafter to at least 25% by the 2025
25    delivery year; and increasing at least 2% each delivery
26    year thereafter to at least 35% by the 2030 delivery year,

 

 

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1    continuing at that percentage for each delivery year
2    thereafter.
3            (A) By the end of the 2020 delivery year:
4                (i) 75% of the total renewable energy credits
5            procured shall come from wind generation, of which
6            at least 25% shall come from new wind projects; and
7                (ii) 5% of the total renewable energy credits
8            procured or the equivalent amount of renewable
9            energy credits from 1,000 megawatts of solar
10            photovoltaic nameplate capacity, whichever is
11            larger, shall come from new photovoltaic projects;
12            of that amount, to the extent possible, the Agency
13            shall procure 75% from photovoltaic projects using
14            the program outlined in paragraph (1.25) of this
15            subdivision (c) from distributed renewable energy
16            devices or community solar projects and shall give
17            preference to brownfield solar projects that are
18            not community solar projects for the remaining
19            25%.
20            (B) By the end of the 2025 delivery year:
21                (i) 75% of the total renewable energy credits
22            procured shall come from wind generation, of which
23            at least 25% shall come from new wind projects; and
24                (ii) 6% of the total renewable energy credits
25            procured or the equivalent amount of renewable
26            energy credits from 1,500 megawatts of solar

 

 

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1            photovoltaic nameplate capacity, whichever is
2            larger, shall come from new photovoltaic projects;
3            of that amount, to the extent possible the Agency
4            shall procure 75% from photovoltaic projects using
5            the program outlined in paragraph (1.25) of this
6            subdivision (c) from distributed renewable energy
7            devices or community solar projects and shall give
8            preference to brownfield solar projects that are
9            not community solar projects for the remaining
10            25%.
11        (C) By the end of the 2030 delivery year:
12                (i) 75% of the total renewable energy credits
13            procured shall come from wind generation, of which
14            at least 25% shall come from new wind projects; and
15                (ii) 7% of the total renewable energy credits
16            procured or the equivalent amount of renewable
17            energy credits from 2,000 megawatts of solar
18            photovoltaic nameplate capacity, whichever is
19            larger, shall come from new photovoltaic projects;
20            of that amount, to the extent possible the Agency
21            shall procure 75% from photovoltaic projects using
22            the program outlined in paragraph (1.25) of this
23            subdivision (c) from distributed renewable energy
24            devices or community solar projects and shall give
25            preference to brownfield solar projects that are
26            not community solar projects for the remaining

 

 

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1            25%.
2        Renewable energy credits are eligible to be counted
3    toward the renewable energy requirements of this
4    subsection (c) if the renewable energy facility is located
5    in Illinois, if the facility has a generator
6    interconnection agreement with PJM or MISO, or if the
7    renewable energy facility is located in the United States
8    and the output of the facility is delivered to a
9    transmission asset that is controlled by PJM or MISO, where
10    "delivered" means the generated output of the facility has
11    been demonstrated to have a distribution factor of 25% or
12    greater on the transmission asset of PJM or MISO, and where
13    "distribution factor" means a measurement of the
14    sensitivity of the flow of electricity from a renewable
15    energy generator to a consuming load on a transmission
16    asset under the control of MISO or PJM. In procuring
17    renewable energy credits, the Agency may consider bid
18    selection criteria that include public interest factors,
19    such as the potential to increase fuel and resource
20    diversity in Illinois, enhance system reliability and
21    resiliency, and contribute to a cleaner and healthier
22    environment for the citizens of Illinois. In its long-term
23    plan, the Agency shall develop the method for incorporating
24    these public interest factors, in addition to bid price,
25    into its bid selection process. The Agency's method may
26    include, but may not be limited to, quantitatively scoring

 

 

HB2607- 54 -LRB099 06217 AMC 30868 b

1    the evaluation of individual bids under public interest
2    criteria or the establishment of procurement minimums for
3    project categories informed by the public interest factors
4    described in this paragraph (1.15).
5        In the event that the rate impact cap in paragraph
6    (1.15) of this subdivision (c) prevents the Agency from
7    meeting all of the percentage goals in this subdivision
8    (c), the Agency shall prioritize compliance with the goals
9    for new wind and photovoltaic projects.
10        As used in this paragraph (1.20):
11        "New wind projects" means wind renewable energy
12    projects (i) that begin energy delivery no earlier than 3
13    years prior to the procurement date and (ii) for projects
14    located within Illinois, for which the owner of the project
15    has certified that not less than the prevailing wage was or
16    will be paid to employees who are engaged in construction
17    activities associated with the project.
18        "New photovoltaic projects" means photovoltaic
19    renewable energy projects (i) that are interconnected at
20    the distribution system level of either an electric
21    utility, a municipal utility as defined in Section 3-105 of
22    the Public Utilities Act, or a rural electric cooperative
23    as defined in Section 3-119 of the Public Utilities Act,
24    (ii) that are energized after January 1, 2016 for the first
25    procurement year or within one year of the procurement date
26    for subsequent procurement years, and (iii) for projects

 

 

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1    over 1,000 kilowatts in nameplate capacity, for which the
2    owner of the project has certified that not less than the
3    prevailing wage was or will be paid to employees who are
4    engaged in construction activities associated with the
5    project.
6        "Prevailing wage" has the same definition as in
7    subsection (F) of Section 5.5(a)(3) of the Enterprise Zone
8    Act.
9        (1.25) The long-term renewable resources procurement
10    plan developed by the Agency in accordance with this
11    subdivision (c) shall include a declining block program for
12    the procurement of renewable energy credits from
13    photovoltaic projects that are distributed renewable
14    energy generation devices or community solar projects. The
15    declining block program shall be designed to provide a
16    transparent schedule of prices and capacity to enable the
17    photovoltaic market to scale up and for renewable energy
18    credit prices to fall at a predictable, sustainable rate
19    over time. The declining block program shall include for
20    each category of eligible projects: (i) a schedule of
21    standard, declining block purchase prices to be offered,
22    (ii) a series of steps, with associated nameplate capacity
23    and purchase prices that decline from step to step, and
24    (iii) automatic opening of the next step as soon as the
25    nameplate capacity and available purchase prices for an
26    open step are fully committed or reserved. Only projects

 

 

HB2607- 56 -LRB099 06217 AMC 30868 b

1    energized on or after January 1, 2016, shall be eligible
2    for the declining block program. For each block group the
3    Agency shall determine the number of blocks, the amount of
4    generation capacity in each block, and the purchase price
5    for each block, provided that the purchase price provided
6    and the total amount of generation in all blocks for all
7    block groups shall be sufficient to meet the goals in
8    paragraph (1.20) of this subdivision (c). The Agency may
9    periodically review the purchase prices and may
10    redistribute available funds as necessary and appropriate,
11    subject to Commission approval as part of the periodic plan
12    revision process described in Section 16-111.5C of the
13    Public Utilities Act.
14        The declining block program shall include at least the
15    following block groups, which may be adjusted upon review
16    by the Agency and approval of the Commission:
17            (A) Distributed renewable energy generation
18        devices with a nameplate capacity of no more than 10
19        kilowatts.
20            (B) Distributed renewable energy generation
21        devices with a nameplate capacity of more than 10
22        kilowatts and no more than 100 kilowatts.
23            (C) Distributed renewable energy generation
24        devices with a nameplate capacity of more than 100
25        kilowatts and no more than 500 kilowatts.
26            (D) Distributed renewable energy generation

 

 

HB2607- 57 -LRB099 06217 AMC 30868 b

1        devices with a nameplate capacity of more than 500
2        kilowatts and no more than 2,000 kilowatts.
3            (E) Distributed renewable energy generation
4        devices with a nameplate capacity of no more than 2,000
5        kilowatts that are owned by a municipality, a school
6        district, a unit of local government, a public
7        university, or a not-for-profit corporation, and
8        primarily used to offset their own electricity load.
9            (F) Community solar projects.
10        For projects that qualify under paragraph (A) of this
11    paragraph (1.25), the renewable energy credit purchase
12    price shall be paid as an upfront payment per installed
13    kilowatt of nameplate capacity paid once the device is
14    energized. The electric utility shall receive all
15    renewable energy credits generated by the project for the
16    first 15 years of operation. For projects that qualify
17    under items (B) through (F) of this paragraph (1.25) and
18    any additional categories included in the long-term
19    renewable resources plan and approved by the Commission,
20    the renewable energy credit purchase price shall be in
21    exchange for an assignment of all renewable energy credits
22    generated by the project for the first 15 years of
23    operation. The Agency shall pay for those credits over the
24    first 5 years of operation of the system through a partial
25    payment made after the system is first energized and
26    additional payments over the first 4 years of operation

 

 

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1    based on actual energy produced. The electric utility shall
2    receive all renewable energy credits generated by the
3    project for the first 15 years of operation.
4        The Agency shall issue a request for qualifications for
5    a third-party program manager to administer the declining
6    block program. The third-party program manager shall be
7    chosen through a competitive bid process based on selection
8    criteria and requirements developed by the Agency,
9    including consideration of prior experience in
10    administering an incentive program for energy efficiency,
11    renewable energy, or other similar resources. The
12    third-party program manager shall be the counterparty to
13    the contract to purchase renewable energy credits from
14    individual systems. The utility shall transfer funds
15    needed to cover the cost of purchasing renewable energy
16    credits and administering the declining block program to
17    the third-party program manager at the order of the
18    Commission. The utility's obligation under this paragraph
19    (1.25) shall be considered met upon transfer of funds to
20    the third-party program manager and retirement of
21    associated renewable energy credits. At least every 2
22    years, the Agency shall select an independent evaluator to
23    review and report on the declining block program and the
24    performance of the declining block program manager. The
25    report should include the number of projects installed, the
26    total installed capacity in kilowatts, the average cost per

 

 

HB2607- 59 -LRB099 06217 AMC 30868 b

1    kilowatt of installed capacity, the total number of jobs,
2    and other economic, social, and environmental benefits
3    created. The report shall be posted on the Agency's website
4    and used, as needed, to revise the declining block program.
5    Upon order of the Commission, the utility shall provide
6    payment for the independent evaluation of the declining
7    block program. Costs associated with evaluation of the
8    declining block program shall not be included in paragraph
9    (1.15) of this subdivision (c), however these costs shall
10    be recoverable as a utility cost of service under the
11    Public Utilities Act. The selection of the third-party
12    program manager, the selection of the independent
13    evaluator, and the procurement process described in this
14    paragraph (1.25) are exempt from the requirements of
15    Section 20-10 of the Illinois Procurement Code.
16        (1.30) The long-term renewable resources procurement
17    plan required by the subdivision (c) shall include a
18    Community Solar Program. The Agency shall develop the
19    Community Solar Program to purchase renewable energy
20    credits from community solar projects with a goal to expand
21    renewable energy generating facility access to a broader
22    group of energy consumers, including those who cannot
23    install renewable energy on their own properties, while
24    prioritizing those persons most sensitive to market
25    barriers.
26        The Agency shall establish the terms, conditions, and

 

 

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1    program requirements for community solar projects as part
2    of the long-term renewable resources plan required by this
3    Section. Any plan approved by the Commission must
4    reasonably allow for the creation, financing, and
5    accessibility of community solar projects and shall allow
6    subscriptions to community solar projects to be portable
7    and transferrable. Electric utilities shall establish a
8    tariff to provide bill credits to subscribers of community
9    solar projects, as specified in an approved long-term
10    renewable resources plan. The community solar bill credits
11    shall account for the fair value of the distributed solar
12    energy and its delivery, generation capacity, transmission
13    capacity, transmission and distribution line losses, and
14    environmental value. The Agency may provide an enhanced
15    bill credit for community solar projects that are located
16    within brownfield sites or within strategic zones
17    identified by the utility with approval by the Commission
18    to provide the greatest benefits to the electric
19    distribution system. If the electrical capacity of a
20    community solar project is not fully subscribed during the
21    first full year of operation, the electric utility shall
22    purchase the energy associated with the unsubscribed
23    capacity at the electric utility's avoided cost of
24    electricity supply over the month period or as otherwise
25    specified by the terms of a power purchase agreement
26    negotiated by the community solar owners or subscribers and

 

 

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1    the electricity provider. After the first full year of
2    operation, if the electrical capacity of a community solar
3    project is not fully subscribed, the electric utility shall
4    purchase the energy associated with the unsubscribed
5    capacity at the electric utility's avoided cost of
6    electricity supply over the month period unless excess
7    capacity is otherwise provided for in a power purchase
8    agreement. The Agency shall purchase renewable energy
9    credits from subscribed shares of community solar projects
10    through the declining block program described in paragraph
11    (6) of this subdivision (c) or through the low income solar
12    program described in Section 1-56 of this Act. The owners
13    of and any subscribers to a community solar project shall
14    not be considered public utilities or alternative retail
15    electricity suppliers under the Public Utilities Act
16    solely as a result of their interest in or subscription to
17    a community solar project and shall not be required to
18    become an alternative retail electric supplier by
19    participating in a community solar project with a public
20    utility.
21        The procurement plans shall include cost-effective
22    renewable energy resources. A minimum percentage of each
23    utility's total supply to serve the load of eligible retail
24    customers, as defined in Section 16-111.5(a) of the Public
25    Utilities Act, procured for each of the following years
26    shall be generated from cost-effective renewable energy

 

 

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1    resources: at least 2% by June 1, 2008; at least 4% by June
2    1, 2009; at least 5% by June 1, 2010; at least 6% by June 1,
3    2011; at least 7% by June 1, 2012; at least 8% by June 1,
4    2013; at least 9% by June 1, 2014; at least 10% by June 1,
5    2015; and increasing by at least 1.5% each year thereafter
6    to at least 25% by June 1, 2025. To the extent that it is
7    available, at least 75% of the renewable energy resources
8    used to meet these standards shall come from wind
9    generation and, beginning on June 1, 2011, at least the
10    following percentages of the renewable energy resources
11    used to meet these standards shall come from photovoltaics
12    on the following schedule: 0.5% by June 1, 2012, 1.5% by
13    June 1, 2013; 3% by June 1, 2014; and 6% by June 1, 2015 and
14    thereafter. Of the renewable energy resources procured
15    pursuant to this Section, at least the following
16    percentages shall come from distributed renewable energy
17    generation devices: 0.5% by June 1, 2013, 0.75% by June 1,
18    2014, and 1% by June 1, 2015 and thereafter. To the extent
19    available, half of the renewable energy resources procured
20    from distributed renewable energy generation shall come
21    from devices of less than 25 kilowatts in nameplate
22    capacity. Renewable energy resources procured from
23    distributed generation devices may also count towards the
24    required percentages for wind and solar photovoltaics.
25    Procurement of renewable energy resources from distributed
26    renewable energy generation devices shall be done on an

 

 

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1    annual basis through multi-year contracts of no less than 5
2    years, and shall consist solely of renewable energy
3    credits.
4        The Agency shall create credit requirements for
5    suppliers of distributed renewable energy. In order to
6    minimize the administrative burden on contracting
7    entities, the Agency shall solicit the use of third-party
8    organizations to aggregate distributed renewable energy
9    into groups of no less than one megawatt in installed
10    capacity. These third-party organizations shall administer
11    contracts with individual distributed renewable energy
12    generation device owners. An individual distributed
13    renewable energy generation device owner shall have the
14    ability to measure the output of his or her distributed
15    renewable energy generation device.
16        For purposes of this subsection (c), "cost-effective"
17    means that the costs of procuring renewable energy
18    resources do not cause the limit stated in paragraph (2) of
19    this subsection (c) to be exceeded and do not exceed
20    benchmarks based on market prices for renewable energy
21    resources in the region, which shall be developed by the
22    procurement administrator, in consultation with the
23    Commission staff, Agency staff, and the procurement
24    monitor and shall be subject to Commission review and
25    approval.
26        (2) (Blank). For purposes of this subsection (c), the

 

 

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1    required procurement of cost-effective renewable energy
2    resources for a particular year shall be measured as a
3    percentage of the actual amount of electricity
4    (megawatt-hours) supplied by the electric utility to
5    eligible retail customers in the planning year ending
6    immediately prior to the procurement. For purposes of this
7    subsection (c), the amount paid per kilowatthour means the
8    total amount paid for electric service expressed on a per
9    kilowatthour basis. For purposes of this subsection (c),
10    the total amount paid for electric service includes without
11    limitation amounts paid for supply, transmission,
12    distribution, surcharges, and add-on taxes.
13        Notwithstanding the requirements of this subsection
14    (c), the total of renewable energy resources procured
15    pursuant to the procurement plan for any single year shall
16    be reduced by an amount necessary to limit the annual
17    estimated average net increase due to the costs of these
18    resources included in the amounts paid by eligible retail
19    customers in connection with electric service to:
20            (A) in 2008, no more than 0.5% of the amount paid
21        per kilowatthour by those customers during the year
22        ending May 31, 2007;
23            (B) in 2009, the greater of an additional 0.5% of
24        the amount paid per kilowatthour by those customers
25        during the year ending May 31, 2008 or 1% of the amount
26        paid per kilowatthour by those customers during the

 

 

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1        year ending May 31, 2007;
2            (C) in 2010, the greater of an additional 0.5% of
3        the amount paid per kilowatthour by those customers
4        during the year ending May 31, 2009 or 1.5% of the
5        amount paid per kilowatthour by those customers during
6        the year ending May 31, 2007;
7            (D) in 2011, the greater of an additional 0.5% of
8        the amount paid per kilowatthour by those customers
9        during the year ending May 31, 2010 or 2% of the amount
10        paid per kilowatthour by those customers during the
11        year ending May 31, 2007; and
12            (E) thereafter, the amount of renewable energy
13        resources procured pursuant to the procurement plan
14        for any single year shall be reduced by an amount
15        necessary to limit the estimated average net increase
16        due to the cost of these resources included in the
17        amounts paid by eligible retail customers in
18        connection with electric service to no more than the
19        greater of 2.015% of the amount paid per kilowatthour
20        by those customers during the year ending May 31, 2007
21        or the incremental amount per kilowatthour paid for
22        these resources in 2011.
23            No later than June 30, 2011, the Commission shall
24        review the limitation on the amount of renewable energy
25        resources procured pursuant to this subsection (c) and
26        report to the General Assembly its findings as to

 

 

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1        whether that limitation unduly constrains the
2        procurement of cost-effective renewable energy
3        resources.
4        (3) (Blank). Through June 1, 2011, renewable energy
5    resources shall be counted for the purpose of meeting the
6    renewable energy standards set forth in paragraph (1) of
7    this subsection (c) only if they are generated from
8    facilities located in the State, provided that
9    cost-effective renewable energy resources are available
10    from those facilities. If those cost-effective resources
11    are not available in Illinois, they shall be procured in
12    states that adjoin Illinois and may be counted towards
13    compliance. If those cost-effective resources are not
14    available in Illinois or in states that adjoin Illinois,
15    they shall be purchased elsewhere and shall be counted
16    towards compliance. After June 1, 2011, cost-effective
17    renewable energy resources located in Illinois and in
18    states that adjoin Illinois may be counted towards
19    compliance with the standards set forth in paragraph (1) of
20    this subsection (c). If those cost-effective resources are
21    not available in Illinois or in states that adjoin
22    Illinois, they shall be purchased elsewhere and shall be
23    counted towards compliance.
24        (4) The electric utility shall retire all renewable
25    energy credits used to comply with the standard.
26        (5) Beginning with the 2010 delivery year and ending

 

 

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1    after the 2016 delivery year year commencing June 1, 2010,
2    an electric utility subject to this subsection (c) shall
3    apply the lesser of the maximum alternative compliance
4    payment rate or the most recent estimated alternative
5    compliance payment rate for its service territory for the
6    corresponding compliance period, established pursuant to
7    subsection (d) of Section 16-115D of the Public Utilities
8    Act to its retail customers that take service pursuant to
9    the electric utility's hourly pricing tariff or tariffs.
10    The electric utility shall retain all amounts collected as
11    a result of the application of the alternative compliance
12    payment rate or rates to such customers, and, beginning in
13    2011, the utility shall include in the information provided
14    under item (1) of subsection (d) of Section 16-111.5 of the
15    Public Utilities Act the amounts collected under the
16    alternative compliance payment rate or rates for the prior
17    year ending May 31. Notwithstanding any limitation on the
18    procurement of renewable energy resources imposed by item
19    (2) of this subsection (c), the Agency shall increase its
20    spending on the purchase of renewable energy resources to
21    be procured by the electric utility for the next plan year
22    by an amount equal to the amounts collected by the utility
23    under the alternative compliance payment rate or rates in
24    the prior year ending May 31. Beginning April 1, 2012, and
25    each year thereafter, the Agency shall prepare a public
26    report for the General Assembly and Illinois Commerce

 

 

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1    Commission that shall include, but not necessarily be
2    limited to:
3            (A) a comparison of the costs associated with the
4        Agency's procurement of renewable energy resources to
5        (1) the Agency's costs associated with electricity
6        generated by other types of generation facilities and
7        (2) the benefits associated with the Agency's
8        procurement of renewable energy resources; and
9            (B) an analysis of the rate impacts associated with
10        the Illinois Power Agency's procurement of renewable
11        resources, including, but not limited to, any
12        long-term contracts, on the eligible retail customers
13        of electric utilities.
14        The analysis shall include the Agency's estimate of the
15    total dollar impact that the Agency's procurement of
16    renewable resources has had on the annual electricity bills
17    of the customer classes that comprise each eligible retail
18    customer class taking service from an electric utility. The
19    Agency's report shall also analyze how the operation of the
20    alternative compliance payment mechanism, any long-term
21    contracts, or other aspects of the applicable renewable
22    portfolio standards impacts the rates of customers of
23    alternative retail electric suppliers.
24        (6) Costs of procuring renewable energy credits
25    pursuant to plans approved under Section 16-111.5C of the
26    Public Utilities Act and associated reasonable expenses

 

 

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1    for implementing the procurement programs, including the
2    costs of administering and evaluating the declining block
3    program, shall be recoverable as a utility cost of service
4    under the Public Utilities Act.
5        (7) In meeting the renewable energy requirements of
6    this subdivision (c), to the extent feasible and consistent
7    with State and federal law, the renewable energy credit
8    procurements, declining block solar program, and community
9    solar program shall provide employment opportunities for
10    all segments of the population and workforce, including
11    minority-owned and female-owned business enterprises, and
12    shall not, consistent with State and federal law,
13    discriminate based on race or socioeconomic status.
14    (d) Clean coal portfolio standard.
15        (1) The procurement plans shall include electricity
16    generated using clean coal. Each utility shall enter into
17    one or more sourcing agreements with the initial clean coal
18    facility, as provided in paragraph (3) of this subsection
19    (d), covering electricity generated by the initial clean
20    coal facility representing at least 5% of each utility's
21    total supply to serve the load of eligible retail customers
22    in 2015 and each year thereafter, as described in paragraph
23    (3) of this subsection (d), subject to the limits specified
24    in paragraph (2) of this subsection (d). It is the goal of
25    the State that by January 1, 2025, 25% of the electricity
26    used in the State shall be generated by cost-effective

 

 

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

 

 

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

 

 

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

 

 

HB2607- 73 -LRB099 06217 AMC 30868 b

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

 

 

HB2607- 74 -LRB099 06217 AMC 30868 b

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

 

 

HB2607- 75 -LRB099 06217 AMC 30868 b

1            pursuant to paragraph (3) of this subsection (d) or
2            item (5) of subsection (d) of Section 16-115 of the
3            Public Utilities Act, whether generated from the
4            synthesis gas derived from coal, from SNG, or from
5            natural gas, shall be credited against the revenue
6            requirement for this initial clean coal facility;
7            (B) power purchase provisions, which shall:
8                (i) provide that the utility party to such
9            sourcing agreement shall pay the contract price
10            for electricity delivered under such sourcing
11            agreement;
12                (ii) require delivery of electricity to the
13            regional transmission organization market of the
14            utility that is party to such sourcing agreement;
15                (iii) require the utility party to such
16            sourcing agreement to buy from the initial clean
17            coal facility in each hour an amount of energy
18            equal to all clean coal energy made available from
19            the initial clean coal facility during such hour
20            times a fraction, the numerator of which is such
21            utility's retail market sales of electricity
22            (expressed in kilowatthours sold) in the State
23            during the prior calendar month and the
24            denominator of which is the total retail market
25            sales of electricity (expressed in kilowatthours
26            sold) in the State by utilities during such prior

 

 

HB2607- 76 -LRB099 06217 AMC 30868 b

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

 

 

HB2607- 77 -LRB099 06217 AMC 30868 b

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

 

 

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1            electricity determined pursuant to the preceding
2            clause (i); and
3                (iii) not require the utility to take physical
4            delivery of the electricity produced by the
5            facility;
6            (D) general provisions, which shall:
7                (i) specify a term of no more than 30 years,
8            commencing on the commercial operation date of the
9            facility;
10                (ii) provide that utilities shall maintain
11            adequate records documenting purchases under the
12            sourcing agreements entered into to comply with
13            this subsection (d) and shall file an accounting
14            with the load forecast that must be filed with the
15            Agency by July 15 of each year, in accordance with
16            subsection (d) of Section 16-111.5 of the Public
17            Utilities Act;
18                (iii) provide that all costs associated with
19            the initial clean coal facility will be
20            periodically reported to the Federal Energy
21            Regulatory Commission and to purchasers in
22            accordance with applicable laws governing
23            cost-based wholesale power contracts;
24                (iv) permit the Illinois Power Agency to
25            assume ownership of the initial clean coal
26            facility, without monetary consideration and

 

 

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1            otherwise on reasonable terms acceptable to the
2            Agency, if the Agency so requests no less than 3
3            years prior to the end of the stated contract term;
4                (v) require the owner of the initial clean coal
5            facility to provide documentation to the
6            Commission each year, starting in the facility's
7            first year of commercial operation, accurately
8            reporting the quantity of carbon emissions from
9            the facility that have been captured and
10            sequestered and report any quantities of carbon
11            released from the site or sites at which carbon
12            emissions were sequestered in prior years, based
13            on continuous monitoring of such sites. If, in any
14            year after the first year of commercial operation,
15            the owner of the facility fails to demonstrate that
16            the initial clean coal facility captured and
17            sequestered at least 50% of the total carbon
18            emissions that the facility would otherwise emit
19            or that sequestration of emissions from prior
20            years has failed, resulting in the release of
21            carbon dioxide into the atmosphere, the owner of
22            the facility must offset excess emissions. Any
23            such carbon offsets must be permanent, additional,
24            verifiable, real, located within the State of
25            Illinois, and legally and practicably enforceable.
26            The cost of such offsets for the facility that are

 

 

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

 

 

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1            with the carbon capture and sequestration
2            requirements set forth in this item (v);
3                (vi) include limits on, and accordingly
4            provide for modification of, the amount the
5            utility is required to source under the sourcing
6            agreement consistent with paragraph (2) of this
7            subsection (d);
8                (vii) require Commission review: (1) to
9            determine the justness, reasonableness, and
10            prudence of the inputs to the formula referenced in
11            subparagraphs (A)(i) through (A)(iii) of paragraph
12            (3) of this subsection (d), prior to an adjustment
13            in those inputs including, without limitation, the
14            capital structure and return on equity, fuel
15            costs, and other operations and maintenance costs
16            and (2) to approve the costs to be passed through
17            to customers under the sourcing agreement by which
18            the utility satisfies its statutory obligations.
19            Commission review shall occur no less than every 3
20            years, regardless of whether any adjustments have
21            been proposed, and shall be completed within 9
22            months;
23                (viii) limit the utility's obligation to such
24            amount as the utility is allowed to recover through
25            tariffs filed with the Commission, provided that
26            neither the clean coal facility nor the utility

 

 

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1            waives any right to assert federal pre-emption or
2            any other argument in response to a purported
3            disallowance of recovery costs;
4                (ix) limit the utility's or alternative retail
5            electric supplier's obligation to incur any
6            liability until such time as the facility is in
7            commercial operation and generating power and
8            energy and such power and energy is being delivered
9            to the facility busbar;
10                (x) provide that the owner or owners of the
11            initial clean coal facility, which is the
12            counterparty to such sourcing agreement, shall
13            have the right from time to time to elect whether
14            the obligations of the utility party thereto shall
15            be governed by the power purchase provisions or the
16            contract for differences provisions;
17                (xi) append documentation showing that the
18            formula rate and contract, insofar as they relate
19            to the power purchase provisions, have been
20            approved by the Federal Energy Regulatory
21            Commission pursuant to Section 205 of the Federal
22            Power Act;
23                (xii) provide that any changes to the terms of
24            the contract, insofar as such changes relate to the
25            power purchase provisions, are subject to review
26            under the public interest standard applied by the

 

 

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

 

 

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

 

 

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

 

 

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

 

 

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

 

 

HB2607- 88 -LRB099 06217 AMC 30868 b

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

 

 

HB2607- 89 -LRB099 06217 AMC 30868 b

1    subsection (d) of this Section and item (5) of subsection
2    (d) of Section 16-115 of the Public Utilities Act, covering
3    electricity generated by such facilities. In the case of
4    sourcing agreements that are power purchase agreements,
5    the contract price for electricity sales shall be
6    established on a cost of service basis. In the case of
7    sourcing agreements that are contracts for differences,
8    the contract price from which the reference price is
9    subtracted shall be established on a cost of service basis.
10    The Agency and the Commission may approve any such utility
11    sourcing agreements that do not exceed cost-based
12    benchmarks developed by the procurement administrator, in
13    consultation with the Commission staff, Agency staff and
14    the procurement monitor, subject to Commission review and
15    approval. The Commission shall have authority to inspect
16    all books and records associated with these clean coal
17    facilities during the term of any such contract.
18        (6) Costs incurred under this subsection (d) or
19    pursuant to a contract entered into under this subsection
20    (d) shall be deemed prudently incurred and reasonable in
21    amount and the electric utility shall be entitled to full
22    cost recovery pursuant to the tariffs filed with the
23    Commission.
24    (e) The draft procurement plans are subject to public
25comment, as required by Section 16-111.5 of the Public
26Utilities Act.

 

 

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1    (f) The Agency shall submit the final procurement plan to
2the Commission. The Agency shall revise a procurement plan if
3the Commission determines that it does not meet the standards
4set forth in Section 16-111.5 of the Public Utilities Act.
5    (g) The Agency shall assess fees to each affected utility
6to recover the costs incurred in preparation of the annual
7procurement plan for the utility.
8    (h) The Agency shall assess fees to each bidder to recover
9the costs incurred in connection with a competitive procurement
10process.
11(Source: P.A. 97-325, eff. 8-12-11; 97-616, eff. 10-26-11;
1297-618, eff. 10-26-11; 97-658, eff. 1-13-12; 97-813, eff.
137-13-12; 98-463, eff. 8-16-13.)
 
14    Section 10. The Public Utilities Act is amended by changing
15Sections 8-101, 8-103, 8-104, 16-107, 16-108.5, 16-108.8,
1616-111.5, 16-111.5B, 16-111.7, 16-115D, and 19-140 and by
17adding Section 16-111.5C as follows:
 
18    (220 ILCS 5/8-101)  (from Ch. 111 2/3, par. 8-101)
19    Sec. 8-101. Duties of public utilities; nondiscrimination.
20A public utility shall furnish, provide, and maintain such
21service instrumentalities, equipment, and facilities as shall
22promote the safety, health, comfort, and convenience of its
23patrons, employees, and public and as shall be in all respects
24adequate, efficient, just, and reasonable.

 

 

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1    All rules and regulations made by a public utility
2affecting or pertaining to its charges or service to the public
3shall be just and reasonable.
4    A public utility shall, upon reasonable notice, furnish to
5all persons who may apply therefor and be reasonably entitled
6thereto, suitable facilities and service, without
7discrimination and without delay.
8    Nothing in this Section shall be construed to prevent a
9public utility from accepting payment electronically or by the
10use of a customer-preferred financially accredited credit or
11debit methodology.
12    A public utility shall not discriminate against
13technologies, regardless of generator, prime mover, or
14inverter, when presented with an application for
15interconnection of a distributed generation facility,
16including without limitation a battery or energy storage
17facility, that operates in parallel with the electric
18distribution system.
19(Source: P.A. 92-22, eff. 6-30-01.)
 
20    (220 ILCS 5/8-103)
21    Sec. 8-103. Energy efficiency and demand-response
22measures.
23    (a) It is the policy of the State that electric utilities
24are required to use cost-effective energy efficiency and
25demand-response measures to reduce delivery load. Requiring

 

 

HB2607- 92 -LRB099 06217 AMC 30868 b

1investment in cost-effective energy efficiency and
2demand-response measures will reduce direct and indirect costs
3to consumers by decreasing environmental impacts, by reducing
4electricity prices in the regional power market, and by
5avoiding or delaying the need for new generation, transmission,
6and distribution infrastructure. It serves the public interest
7to allow electric utilities to recover costs for reasonably and
8prudently incurred expenses for energy efficiency and
9demand-response measures. As used in this Section,
10"cost-effective" means that the measures satisfy the total
11resource cost test. The low-income measures described in
12subsection (f)(4) of this Section shall not be required to meet
13the total resource cost test. For purposes of this Section, the
14terms "energy-efficiency", "demand-response", "electric
15utility", and "total resource cost test" shall have the
16meanings set forth in the Illinois Power Agency Act. For
17purposes of this Section, the amount per kilowatthour means the
18total amount paid for electric service expressed on a per
19kilowatthour basis. For purposes of this Section, the total
20amount paid for electric service includes without limitation
21estimated amounts paid for supply, transmission, distribution,
22surcharges, and add-on-taxes.
23    (b) Electric utilities shall implement cost-effective
24energy efficiency measures to meet the following incremental
25annual energy savings goals:
26        (1) 0.2% of energy delivered in the year commencing

 

 

HB2607- 93 -LRB099 06217 AMC 30868 b

1    June 1, 2008;
2        (2) 0.4% of energy delivered in the year commencing
3    June 1, 2009;
4        (3) 0.6% of energy delivered in the year commencing
5    June 1, 2010;
6        (4) 0.8% of energy delivered in the year commencing
7    June 1, 2011;
8        (5) 1% of energy delivered in the year commencing June
9    1, 2012;
10        (6) 1.4% of energy delivered in the year commencing
11    June 1, 2013;
12        (7) 1.8% of energy delivered in the year commencing
13    June 1, 2014; and
14        (8) 2% of energy delivered in each the year commencing
15    June 1, 2015 and ending on December 31, 2017; and each year
16    thereafter.
17        (9) beginning in January 2018, an amount to be
18    determined by the Illinois Commerce Commission through the
19    process described in subsection (f) of this Section in
20    order to achieve a cumulative annual persisting reduction
21    in electric energy demand from efficiency measures
22    implemented as a result of utility programs from 2012
23    through 2025 of 20%, relative to average annual electricity
24    sales from 2014 through 2016, by the year ending December
25    31 2025; cumulative persisting annual reductions are the
26    reductions realized in a given year from measures installed

 

 

HB2607- 94 -LRB099 06217 AMC 30868 b

1    in either the that year or in previous years that are still
2    operational and providing savings in that year because they
3    have not yet reached the end of their useful life; and
4    After 2025, the incremental annual energy goal shall be an
5amount to be determined by the Illinois Commerce Commission in
6order to fully capture the cost-effective potential for
7electricity savings as assessed by the Illinois Power Agency
8under subsection (j-10) of this Section.
9    Electric utilities may comply with this subsection (b) by
10meeting the annual incremental savings goal in the applicable
11year or by showing that the total cumulative annual savings
12within a 3-year planning period associated with measures
13implemented after May 31, 2014 was equal to the sum of each
14annual incremental savings requirement from May 31, 2014
15through the end of the applicable year. Beginning January 1,
162018, electric utilities may comply by showing that the total
17cumulative annual savings persisting the last year of the
18applicable 4-year planning period was equal to the cumulative
19persisting annual savings required in that year by the Illinois
20Commerce Commission pursuant to the plans approved under
21subsection (f) of this Section. Annually, beginning on March 1,
222019, each participating utility shall file third-party
23evaluations of the savings achieved in the preceding year.
24Within 5 days after the filing, any person objecting to the
25filing shall file an objection. Within 10 days after the
26filing, the Commission shall determine whether a hearing is

 

 

HB2607- 95 -LRB099 06217 AMC 30868 b

1necessary. The Commission shall enter its order confirming or
2modifying the savings estimates within 90 days after the filing
3date.
4    (c) Electric utilities shall implement cost-effective
5demand-response measures to reduce peak demand by 0.1% over the
6prior year for its delivery customers eligible retail
7customers, as defined in Section 16-111.5 of this Act, and for
8customers that elect hourly service from the utility pursuant
9to Section 16-107 of this Act, provided those customers have
10not been declared competitive. This requirement commences June
111, 2008 and continues for 10 years.
12    (d) Notwithstanding the requirements of subsections (b)
13and (c) of this Section, an electric utility shall reduce the
14amount of energy efficiency and demand-response measures
15implemented over a 3-year planning period by an amount
16necessary to limit the estimated average annual increase in the
17amounts paid by retail customers in connection with electric
18service due to the cost of those measures to:
19        (1) in 2008, no more than 0.5% of the amount paid per
20    kilowatthour by those customers during the year ending May
21    31, 2007;
22        (2) in 2009, the greater of an additional 0.5% of the
23    amount paid per kilowatthour by those customers during the
24    year ending May 31, 2008 or 1% of the amount paid per
25    kilowatthour by those customers during the year ending May
26    31, 2007;

 

 

HB2607- 96 -LRB099 06217 AMC 30868 b

1        (3) in 2010, the greater of an additional 0.5% of the
2    amount paid per kilowatthour by those customers during the
3    year ending May 31, 2009 or 1.5% of the amount paid per
4    kilowatthour by those customers during the year ending May
5    31, 2007;
6        (4) in 2011, the greater of an additional 0.5% of the
7    amount paid per kilowatthour by those customers during the
8    year ending May 31, 2010 or 2% of the amount paid per
9    kilowatthour by those customers during the year ending May
10    31, 2007; and
11        (5) in 2012 and in each subsequent year through 2017
12    thereafter, the amount of energy efficiency and
13    demand-response measures implemented for any single year
14    shall be reduced by an amount necessary to limit the
15    estimated average net increase due to the cost of these
16    measures included in the amounts paid by eligible retail
17    customers in connection with electric service to no more
18    than the greater of 2.015% of the amount paid per
19    kilowatthour by those customers during the year ending May
20    31, 2007 or the incremental amount per kilowatthour paid
21    for these measures in 2011.
22    No later than June 30, 2011, the Commission shall review
23the limitation on the amount of energy efficiency and
24demand-response measures implemented pursuant to this Section
25and report to the General Assembly its findings as to whether
26that limitation unduly constrains the procurement of energy

 

 

HB2607- 97 -LRB099 06217 AMC 30868 b

1efficiency and demand-response measures.
2    For utility efficiency programs offered on or after January
32018, the amount of savings shall be limited only to the extent
4necessary to ensure that the measures installed will, in the
5aggregate, result in net benefits to customers when the full
6costs of the efficiency programs are compared with the full
7benefits, as defined in the total resource cost test.
8    (e) Electric utilities shall be responsible for overseeing
9the design, development, and filing of energy efficiency and
10demand-response plans with the Commission. Electric utilities
11shall implement 100% of the demand-response measures in the
12plans. Electric utilities shall implement 75% of the energy
13efficiency measures approved by the Commission, and may, as
14part of that implementation, outsource various aspects of
15program development and implementation. The remaining 25% of
16those energy efficiency measures approved by the Commission
17shall be implemented by the Department of Commerce and Economic
18Opportunity, and must be designed in conjunction with the
19utility and the filing process. The Department may outsource
20development and implementation of energy efficiency measures.
21A minimum of 10% of the entire portfolio of cost-effective
22energy efficiency measures shall be procured from units of
23local government, municipal corporations, school districts,
24and community college districts. A minimum of 12.5% of the
25entire portfolio of cost-effective energy efficiency measures
26shall be allocated to programs that serve low-income

 

 

HB2607- 98 -LRB099 06217 AMC 30868 b

1residential customers. The Department shall coordinate the
2implementation of these measures. As much as half of the
3minimum low-income requirement may be met through energy
4efficiency measures that result in savings related to fuels
5other than electricity if necessary:
6        (1) to comprehensively capture treatment of efficiency
7    opportunities for low-income residential customers;
8        (2) to enable effective administration of low-income
9    programs; or
10        (3) to address limitations on availability of other
11    funding sources for efficiency measures to improve the
12    efficiency of use of natural gas, fuel oil, or other fuels
13    used by low-income residential customers.
14The Department shall coordinate the implementation of these
15measures.
16    The apportionment of the dollars to cover the costs to
17implement the Department's share of the portfolio of energy
18efficiency measures shall be made to the Department once the
19Department has executed rebate agreements, grants, or
20contracts for energy efficiency measures and provided
21supporting documentation for those rebate agreements, grants,
22and contracts to the utility. The Department is authorized to
23adopt any rules necessary and prescribe procedures in order to
24ensure compliance by applicants in carrying out the purposes of
25rebate agreements for energy efficiency measures implemented
26by the Department made under this Section.

 

 

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1    The details of the measures implemented by the Department
2shall be submitted by the Department to the Commission in
3connection with the utility's filing regarding the energy
4efficiency and demand-response measures that the utility
5implements.
6    A utility providing approved energy efficiency and
7demand-response measures in the State before December 31, 2017
8shall be permitted to recover costs of those measures through
9an automatic adjustment clause tariff filed with and approved
10by the Commission. The tariff shall be established outside the
11context of a general rate case. Each year the Commission shall
12initiate a review to reconcile any amounts collected with the
13actual costs and to determine the required adjustment to the
14annual tariff factor to match annual expenditures. Beginning
15January 1, 2018, a participating utility providing approved
16energy efficiency and demand-response measures in the State
17that has elected to be subject to Section 16-108.5 of the
18Public Utilities Act may recover the costs of those measures as
19part of its cost of service in its performance-based formula
20rate as provided in paragraph (1) of subsection (c) of Section
2116-108.5.
22    Each utility shall include, in its recovery of costs, the
23costs estimated for both the utility's and the Department's
24implementation of energy efficiency and demand-response
25measures. Costs collected by the utility for measures
26implemented by the Department shall be submitted to the

 

 

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

 

 

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1Department and the utility shall file their respective plans
2with the Commission and the Commission shall determine an
3appropriate division of measures and programs that meets the
4requirements of this Section.
5    If the Department is unable to meet incremental annual
6performance goals for the portion of the portfolio implemented
7by the Department, then the utility and the Department shall
8jointly submit a modified filing to the Commission explaining
9the performance shortfall and recommending an appropriate
10course going forward, including any program modifications that
11may be appropriate in light of the evaluations conducted under
12item (7) of subsection (f) of this Section. In this case, the
13utility obligation to collect the Department's costs and turn
14over those funds to the Department under this subsection (e)
15shall continue only if the Commission approves the
16modifications to the plan proposed by the Department.
17    (f) No later than November 15, 2007, each electric utility
18shall file an energy efficiency and demand-response plan with
19the Commission to meet the energy efficiency and
20demand-response standards for 2008 through 2010. No later than
21October 1, 2010, each electric utility shall file an energy
22efficiency and demand-response plan with the Commission to meet
23the energy efficiency and demand-response standards for 2011
24through 2013. By September 1, 2013, each electric utility shall
25file an energy efficiency and demand-response plan for 2014
26through 2017. By January 1, 2016, the Illinois Power Agency

 

 

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1shall publish a draft statewide energy efficiency potential
2study that assesses the technical, economic, and maximum
3cost-effective achievable potential for energy efficiency for
4each electric utility service territory from 2018 through 2021
5and from 2022 through 2025. The Agency shall seek input from
6stakeholders in advance of conducting the study. After the
7draft study is published, the Agency shall accept public
8comments on the study through March 1, 2016 and shall transmit
9a final proposed study to the Commission by April 15, 2017. The
10Commission shall approve the study or approve with
11modifications by June 1, 2016. By January 1, 2017, each
12electric utility and the Department shall file an energy
13efficiency plan for the period beginning January 1, 2018
14through December 31, 2021 that seeks to achieve a cumulative
15persisting annual reduction in electricity demand in 2021, from
16efficiency measures installed as a result of its programs from
172012 through 2021, of at least 12% compared to average annual
18electricity sales from 2014 through 2016, unless such levels
19have been clearly shown by the Illinois Power Agency's
20potential study to not be cost-effective or achievable, in
21which case the plans should be designed to capture all of the
22cost-effective potential for energy savings identified as
23achievable in the potential study completed by the Illinois
24Power Agency. By January 1, 2020 and every 4 years thereafter,
25the Illinois Power Agency shall publish a second draft
26statewide energy efficiency potential study updating its

 

 

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1assessment of the cost-effective achievable potential for
2energy efficiency for each electric utility service territory
3from 2022 through 2025. The agency shall seek input from
4stakeholders in advance of conducting the study. The agency
5will accept public comments on the draft study through March 1,
62020 and shall transmit a final proposed study to the
7Commission by April 15, 2020. The Commission shall approve the
8study or approve with modifications by June 1, 2020. By January
91, 2021, each electric utility and the Department shall file an
10energy efficiency plan for the period beginning January 1, 2022
11through December 31, 2025 that seeks to achieve a cumulative
12persisting annual reduction in electricity demand in 2025, from
13efficiency measures installed as a result of its programs from
142012 through 2025, of at least 20% compared to average annual
15electricity sales from 2014 through 2016, unless such levels
16have been clearly shown by the Illinois Power Agency's study to
17not be cost-effective or achievable, in which case the plans
18should be designed to capture all of the cost-effective
19potential for energy savings identified in the potential study
20completed by the Illinois Power Agency. On January 1, 2024 and
21every 4 years thereafter, each electric utility and the
22Department shall file an energy efficiency plan covering a
234-year period beginning January 1 of the following year. Every
243 years thereafter, each electric utility shall file, no later
25than September 1, an energy efficiency and demand-response plan
26with the Commission. If a utility does not file such a plan by

 

 

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1the deadlines described in this Section September 1 of an
2applicable year, it shall face a penalty of $100,000 per day
3until the plan is filed. Each utility's plan shall set forth
4the utility's proposals to meet the utility's portion of the
5energy efficiency standards identified in subsection (b) and
6the demand-response standards identified in subsection (c) of
7this Section as modified by subsections (d) and (e), taking
8into account the unique circumstances of the utility's service
9territory. The Commission shall seek public comment on the
10utility's plan and shall issue an order approving or
11disapproving each plan within 6 5 months after its submission.
12If the Commission disapproves a plan, the Commission shall,
13within 30 days, describe in detail the reasons for the
14disapproval and describe a path by which the utility may file a
15revised draft of the plan to address the Commission's concerns
16satisfactorily. If the utility does not refile with the
17Commission within 60 days, the utility shall be subject to
18penalties at a rate of $100,000 per day until the plan is
19filed. This process shall continue, and penalties shall accrue,
20until the utility has successfully filed a portfolio of energy
21efficiency and demand-response measures. Penalties shall be
22deposited into the Energy Efficiency Trust Fund. In submitting
23proposed energy efficiency and demand-response plans and
24funding levels to meet the savings goals adopted by this Act
25the utility shall:
26        (1) Demonstrate that its proposed energy efficiency

 

 

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1    and demand-response measures will achieve the requirements
2    that are identified in subsections (b) and (c) of this
3    Section, as modified by subsections (d) and (e).
4        (2) Present specific proposals to implement new
5    building and appliance standards that have been placed into
6    effect.
7        (3) Present estimates of the total amount paid for
8    electric service expressed on a per kilowatthour basis
9    associated with the proposed portfolio of measures
10    designed to meet the requirements that are identified in
11    subsections (b) and (c) of this Section, as modified by
12    subsections (d) and (e).
13        (4) Coordinate with the Department to present a
14    portfolio of energy efficiency measures proportionate to
15    the share of total annual utility revenues in Illinois from
16    households at or below 150% of the poverty level. The
17    energy efficiency programs shall be targeted to households
18    with incomes at or below 80% of area median income.
19        (5) Demonstrate that its overall portfolio of energy
20    efficiency and demand-response measures, not including
21    programs covered by item (4) of this subsection (f), are
22    cost-effective using the total resource cost test and
23    represent a diverse cross-section of opportunities for
24    customers of all rate classes to participate in the
25    programs.
26        (5.5) Include meaningful opportunities for third-party

 

 

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1    energy efficiency businesses to deliver energy savings.
2        (5.10) Ensure that the portfolio as a whole, including
3    the portion administered by the Department of Commerce and
4    Economic Opportunity and programs offered by third-party
5    energy service providers, include opportunities for a
6    diverse set of building types, including both program
7    offering tailored to the needs of specific building types
8    and opportunities to source energy efficiency savings from
9    building, including, but not limited to, hospitals, health
10    care facilities, long-term care facilities, units of local
11    government, school districts, park districts, cultural
12    institutions, museums, facilities licensed under the Child
13    Care Act of 1969, preschools, churches and houses of
14    worship, public universities, private colleges, community
15    college districts, and wastewater and drinking water
16    treatment plant agencies and operators.
17        (5.15) Demonstrate that the utility consulted with
18    interested stakeholders, including customer groups,
19    environmental advocates, Commission staff, the Illinois
20    Commission on Environmental Justice, and other entities
21    who have participated in Commission proceedings to
22    consider the approval of past energy efficiency plans under
23    this Section and that those entities concerns and input
24    have been taken into consideration during the development
25    of the proposed plan.
26        (5.20) Ensure that the portfolio maximizes the use of

 

 

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1    cost-effective measures with measure lives of 10 years or
2    greater.
3        (6) Include a proposed cost-recovery tariff mechanism
4    to fund the proposed energy efficiency and demand-response
5    measures and to ensure the recovery of the prudently and
6    reasonably incurred costs of Commission-approved programs.
7    Beginning in 2018, a participating utility, as defined in
8    Section 16-108.5, providing approved energy efficiency and
9    demand-response measures in the State shall recover the
10    costs of those measures as part of its performance-based
11    formula rate as provided in paragraph (1) of subsection (c)
12    of Section 16-108.5.
13        (7) Provide for an annual independent evaluation of the
14    performance of the cost-effectiveness of the utility's
15    portfolio of measures and the Department's portfolio of
16    measures, as well as a full review of the full multi-year
17    portfolio 3-year results of the broader net program impacts
18    and, to the extent practical, for adjustment of the
19    measures on a going-forward basis as a result of the
20    evaluations. The resources dedicated to evaluation shall
21    not exceed 3% of portfolio resources in any given year. The
22    evaluations shall be performed by independent experts that
23    are retained for this purpose by the Illinois Commerce
24    Commission.
25    (g) No more than 3% of energy efficiency and
26demand-response program revenue may be allocated for research,

 

 

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1development, or pilot deployment of new equipment or measures
2demonstration of breakthrough equipment and devices.
3    (h) This Section does not apply to an electric utility that
4on December 31, 2005 provided electric service to fewer than
5100,000 customers in Illinois.
6    (i) If, after 2 years, an electric utility fails to meet
7the efficiency standard specified in subsection (b) of this
8Section, as modified by subsections (d) and (e), it shall make
9a contribution to the Low-Income Home Energy Assistance
10Program. The combined total liability for failure to meet the
11goal shall be $1,000,000, which shall be assessed as follows: a
12large electric utility shall pay $665,000, and a medium
13electric utility shall pay $335,000. If, after 3 years, an
14electric utility fails to meet the efficiency standard
15specified in subsection (b) of this Section, as modified by
16subsections (d) and (e), it shall make a contribution to the
17Low-Income Home Energy Assistance Program. The combined total
18liability for failure to meet the goal shall be $1,000,000,
19which shall be assessed as follows: a large electric utility
20shall pay $665,000, and a medium electric utility shall pay
21$335,000. In addition, the responsibility for implementing the
22energy efficiency measures of the utility making the payment
23shall be transferred to the Illinois Power Agency if, after 3
24years, or in any subsequent 3-year period, the utility fails to
25meet the efficiency standard specified in subsection (b) of
26this Section, as modified by subsections (d) and (e). The

 

 

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1Agency shall implement a competitive procurement program to
2procure resources necessary to meet the standards specified in
3this Section as modified by subsections (d) and (e), with costs
4for those resources to be recovered in the same manner as
5products purchased through the procurement plan as provided in
6Section 16-111.5. The Director shall implement this
7requirement in connection with the procurement plan as provided
8in Section 16-111.5.
9    For purposes of this Section, (i) a "large electric
10utility" is an electric utility that, on December 31, 2005,
11served more than 2,000,000 electric customers in Illinois; (ii)
12a "medium electric utility" is an electric utility that, on
13December 31, 2005, served 2,000,000 or fewer but more than
14100,000 electric customers in Illinois; and (iii) Illinois
15electric utilities that are affiliated by virtue of a common
16parent company are considered a single electric utility.
17    (j) If, after 3 years, or any subsequent 3-year period, the
18Department fails to implement the Department's share of energy
19efficiency measures required by the standards in subsection
20(b), then the Illinois Power Agency may assume responsibility
21for and control of the Department's share of the required
22energy efficiency measures. The Agency shall implement a
23competitive procurement program to procure resources necessary
24to meet the standards specified in this Section, with the costs
25of these resources to be recovered in the same manner as
26provided for the Department in this Section.

 

 

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1    (j-5) By June 1, 2016 and every 4 years thereafter, the
2Department of Commerce and Economic Opportunity shall perform
3and make publicly available a study assessing the job creation
4impact of implementation of energy efficiency programs and
5policies in Illinois. The Department shall seek input from
6stakeholders in advance of conducting the study.
7    (j-10) For the purposes of conducting the energy efficiency
8potential studies required in subsection (f) of this Section,
9the Illinois Power Agency shall:
10        (1) base estimates of the portion of economic potential
11    that could be achieved on document experience of the most
12    successful programs in other jurisdictions in each of the
13    specific efficiency markets being analyzed;
14        (2) include impacts from emergence of new technologies
15    that can reasonably be expected to emerge after the study
16    is conducted but during the period covered by the study;
17        (3) account for potential for measure costs to decline
18    as volumes of sales increase;
19        (4) account for economies that could be achieved
20    through joint electric-gas program delivery or
21    coordination;
22        (5) include estimates of potential from behavioral
23    changes and process improvements (in addition to
24    technologies);
25        (6) include estimates of impacts from fuel-switching
26    measures; and

 

 

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1        (7) include estimates of impacts from either
2    supporting adoption of stricter building codes or
3    equipment standards or better compliance with existing
4    codes and standards.
5    (j-15) The Commission shall issue an order extending the
6programs approved under subsection (f) of this Section for the
7period beginning June 1, 2014 and ending May 31, 2017 so that
8these programs continue to be offered until December 31, 2017.
9The savings goals and budgets associated with these approved
10programs shall be modified to ensure that the programs will
11continue to operate and acquire additional savings during this
12period and under the same cost-effectiveness requirements
13applicable when the programs were approved.
14    (k) No electric utility shall be deemed to have failed to
15meet the energy efficiency standards to the extent any such
16failure is due to a failure of the Department or the Agency.
17    (l) In meeting the energy efficiency requirements of this
18Section, to the extent feasible and consistent with State and
19federal law, the energy efficiency credit procurements,
20declining block solar program, and community solar program
21should provide employment opportunities for all segments of the
22population and workforce, including minority-owned and
23female-owned business enterprises, and shall not, consistent
24with State and federal law, discriminate based on race or
25socioeconomic status.
26(Source: P.A. 97-616, eff. 10-26-11; 97-841, eff. 7-20-12;

 

 

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198-90, eff. 7-15-13.)
 
2    (220 ILCS 5/8-104)
3    Sec. 8-104. Natural gas energy efficiency programs.
4    (a) It is the policy of the State that natural gas
5utilities and the Department of Commerce and Economic
6Opportunity are required to use cost-effective energy
7efficiency to reduce direct and indirect costs to consumers. It
8serves the public interest to allow natural gas utilities to
9recover costs for reasonably and prudently incurred expenses
10for cost-effective energy efficiency measures.
11    (b) For purposes of this Section, "energy efficiency" means
12measures that reduce the amount of energy required to achieve a
13given end use. "Energy efficiency" also includes measures that
14reduce the total Btus of electricity and natural gas needed to
15meet the end use or uses. "Cost-effective" means that the
16measures satisfy the total resource cost test, which, for
17purposes of this Section, has the meaning given to that term in
18Section 1-10 of the Illinois Power Agency Act. means a standard
19that is met if, for an investment in energy efficiency, the
20benefit-cost ratio is greater than one. The benefit-cost ratio
21is the ratio of the net present value of the total benefits of
22the measures to the net present value of the total costs as
23calculated over the lifetime of the measures. The total
24resource cost test compares the sum of avoided natural gas
25utility costs, representing the benefits that accrue to the

 

 

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1system and the participant in the delivery of those efficiency
2measures, as well as other quantifiable societal benefits,
3including avoided electric utility costs, to the sum of all
4incremental costs of end use measures (including both utility
5and participant contributions), plus costs to administer,
6deliver, and evaluate each demand-side measure, to quantify the
7net savings obtained by substituting demand-side measures for
8supply resources. In calculating avoided costs, reasonable
9estimates shall be included for financial costs likely to be
10imposed by future regulation of emissions of greenhouse gases.
11The low-income programs described in item (4) of subsection (f)
12of this Section shall not be required to meet the total
13resource cost test.
14    (c) Natural gas utilities shall implement cost-effective
15energy efficiency measures to meet at least the following
16natural gas savings requirements, which shall be based upon the
17total amount of gas delivered to retail customers, other than
18the customers described in subsection (m) of this Section,
19during calendar year 2009 multiplied by the applicable
20percentage. Natural gas utilities may comply with this Section
21by meeting the annual incremental savings goal in the
22applicable year or by showing that total cumulative annual
23savings within a 3-year planning period associated with
24measures implemented after May 31, 2011 were equal to the sum
25of each annual incremental savings requirement from May 31,
262011 through the end of the applicable year:

 

 

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1        (1) 0.2% by May 31, 2012;
2        (2) an additional 0.4% by May 31, 2013, increasing
3    total savings to .6%;
4        (3) an additional 0.6% by May 31, 2014, increasing
5    total savings to 1.2%;
6        (4) an additional 0.8% by May 31, 2015, increasing
7    total savings to 2.0%;
8        (5) an additional 1% by May 31, 2016, increasing total
9    savings to 3.0%;
10        (6) an additional 1.2% by May 31, 2017, increasing
11    total savings to 4.2%;
12        (7) an additional 1.4% by May 31, 2018, increasing
13    total savings to 5.6%;
14        (8) an additional 1.5% by May 31, 2019, increasing
15    total savings to 7.1%; and
16        (9) an additional 1.5% in each 12-month period
17    thereafter.
18    (d) Notwithstanding the requirements of subsection (c) of
19this Section, a natural gas utility shall limit the amount of
20energy efficiency implemented in any 3-year reporting period
21established by subsection (f) of Section 8-104 of this Act, by
22an amount necessary to limit the estimated average increase in
23the amounts paid by retail customers in connection with natural
24gas service to no more than 2% in the applicable 3-year
25reporting period. The energy savings requirements in
26subsection (c) of this Section may be reduced by the Commission

 

 

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1for the subject plan, if the utility demonstrates by
2substantial evidence that it is highly unlikely that the
3requirements could be achieved without exceeding the
4applicable spending limits in any 3-year reporting period. No
5later than September 1, 2013, the Commission shall review the
6limitation on the amount of energy efficiency measures
7implemented pursuant to this Section and report to the General
8Assembly, in the report required by subsection (k) of this
9Section, its findings as to whether that limitation unduly
10constrains the procurement of energy efficiency measures.
11    (e) Natural gas utilities shall be responsible for
12overseeing the design, development, and filing of their
13efficiency plans with the Commission. The utility shall utilize
1475% of the available funding associated with energy efficiency
15programs approved by the Commission, and may outsource various
16aspects of program development and implementation. The
17remaining 25% of available funding shall be used by the
18Department of Commerce and Economic Opportunity to implement
19energy efficiency measures that achieve no less than 20% of the
20requirements of subsection (c) of this Section. Such measures
21shall be designed in conjunction with the utility and approved
22by the Commission. The Department may outsource development and
23implementation of energy efficiency measures. A minimum of 10%
24of the entire portfolio of cost-effective energy efficiency
25measures shall be procured from local government, municipal
26corporations, school districts, and community college

 

 

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1districts. Five percent of the entire portfolio of
2cost-effective energy efficiency measures may be granted to
3local government and municipal corporations for market
4transformation initiatives. The Department shall coordinate
5the implementation of these measures and shall integrate
6delivery of natural gas efficiency programs with electric
7efficiency programs delivered pursuant to Section 8-103 of this
8Act, unless the Department can show that integration is not
9feasible.
10    The apportionment of the dollars to cover the costs to
11implement the Department's share of the portfolio of energy
12efficiency measures shall be made to the Department once the
13Department has executed rebate agreements, grants, or
14contracts for energy efficiency measures and provided
15supporting documentation for those rebate agreements, grants,
16and contracts to the utility. The Department is authorized to
17adopt any rules necessary and prescribe procedures in order to
18ensure compliance by applicants in carrying out the purposes of
19rebate agreements for energy efficiency measures implemented
20by the Department made under this Section.
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 measures that the utility implements.
25    A utility providing approved energy efficiency measures in
26this State shall be permitted to recover costs of those

 

 

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

 

 

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

 

 

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1utility obligation to collect the Department's costs and turn
2over those funds to the Department under this subsection (e)
3shall continue only if the Commission approves the
4modifications to the plan proposed by the Department.
5    (f) No later than October 1, 2010, each gas utility shall
6file an energy efficiency plan with the Commission to meet the
7energy efficiency standards through May 31, 2014. Every 3 years
8thereafter, each utility shall file, no later than October 1,
9an energy efficiency plan with the Commission, except that for
10plans covering 2018 through 2025, each gas utility shall file
11plans on the same schedule as is required for the electric
12utilities under subsection (f) of Section 8-103 of this Act. If
13a utility does not file such a plan by the statutory deadline
14described in this Section October 1 of the applicable year,
15then it shall face a penalty of $100,000 per day until the plan
16is filed. Each utility's plan shall set forth the utility's
17proposals to meet the utility's portion of the energy
18efficiency standards identified in subsection (c) of this
19Section, as modified by subsection (d) of this Section, 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. If the Commission disapproves a plan,
24the Commission shall, within 30 days, describe in detail the
25reasons for the disapproval and describe a path by which the
26utility may file a revised draft of the plan to address the

 

 

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1Commission's concerns satisfactorily. If the utility does not
2refile with the Commission within 60 days after the
3disapproval, the utility shall be subject to penalties at a
4rate of $100,000 per day until the plan is filed. This process
5shall continue, and penalties shall accrue, until the utility
6has successfully filed a portfolio of energy efficiency
7measures. Penalties shall be deposited into the Energy
8Efficiency Trust Fund and the cost of any such penalties may
9not be recovered from ratepayers. In submitting proposed energy
10efficiency plans and funding levels to meet the savings goals
11adopted by this Act the utility shall:
12        (1) Demonstrate that its proposed energy efficiency
13    measures will achieve the requirements that are identified
14    in subsection (c) of this Section, as modified by
15    subsection (d) of this Section.
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 gas
20    service expressed on a per therm basis associated with the
21    proposed portfolio of measures designed to meet the
22    requirements that are identified in subsection (c) of this
23    Section, as modified by subsection (d) of this Section.
24        (4) Coordinate with the Department to present a
25    portfolio of energy efficiency measures proportionate to
26    the share of total annual utility revenues in Illinois from

 

 

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1    households at or below 150% of the poverty level. Such
2    programs shall be targeted to households with incomes at or
3    below 80% of area median income.
4        (5) Demonstrate that its overall portfolio of energy
5    efficiency measures, not including programs covered by
6    item (4) of this subsection (f), are cost-effective using
7    the total resource cost test and represent a diverse cross
8    section of opportunities for customers of all rate classes
9    to participate in the programs.
10        (6) Demonstrate that a gas utility affiliated with an
11    electric utility that is required to comply with Section
12    8-103 of this Act has integrated gas and electric
13    efficiency measures into a single program that reduces
14    program or participant costs and appropriately allocates
15    costs to gas and electric ratepayers. The Department shall
16    integrate all gas and electric programs it delivers in any
17    such utilities' service territories, unless the Department
18    can show that integration is not feasible or appropriate.
19        (7) Include a proposed cost recovery tariff mechanism
20    to fund the proposed energy efficiency measures and to
21    ensure the recovery of the prudently and reasonably
22    incurred costs of Commission-approved programs.
23        (8) Provide for quarterly status reports tracking
24    implementation of and expenditures for the utility's
25    portfolio of measures and the Department's portfolio of
26    measures, an annual independent review, and a full

 

 

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1    independent evaluation of the 3-year results of the
2    performance and the cost-effectiveness of the utility's
3    and Department's portfolios of measures and broader net
4    program impacts and, to the extent practical, for
5    adjustment of the measures on a going forward basis as a
6    result of the evaluations. The resources dedicated to
7    evaluation shall not exceed 3% of portfolio resources in
8    any given 3-year period.
9    (g) No more than 3% of expenditures on energy efficiency
10measures may be allocated for demonstration of breakthrough
11equipment and devices.
12    (h) Illinois natural gas utilities that are affiliated by
13virtue of a common parent company may, at the utilities'
14request, be considered a single natural gas utility for
15purposes of complying with this Section.
16    (i) If, after 3 years, a gas utility fails to meet the
17efficiency standard specified in subsection (c) of this Section
18as modified by subsection (d), then it shall make a
19contribution to the Low-Income Home Energy Assistance Program.
20The total liability for failure to meet the goal shall be
21assessed as follows:
22        (1) a large gas utility shall pay $600,000;
23        (2) a medium gas utility shall pay $400,000; and
24        (3) a small gas utility shall pay $200,000.
25    For purposes of this Section, (i) a "large gas utility" is
26a gas utility that on December 31, 2008, served more than

 

 

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11,500,000 gas customers in Illinois; (ii) a "medium gas
2utility" is a gas utility that on December 31, 2008, served
3fewer than 1,500,000, but more than 500,000 gas customers in
4Illinois; and (iii) a "small gas utility" is a gas utility that
5on December 31, 2008, served fewer than 500,000 and more than
6100,000 gas customers in Illinois. The costs of this
7contribution may not be recovered from ratepayers.
8    If a gas utility fails to meet the efficiency standard
9specified in subsection (c) of this Section, as modified by
10subsection (d) of this Section, in any 2 consecutive 3-year
11planning periods, then the responsibility for implementing the
12utility's energy efficiency measures shall be transferred to an
13independent program administrator selected by the Commission.
14Reasonable and prudent costs incurred by the independent
15program administrator to meet the efficiency standard
16specified in subsection (c) of this Section, as modified by
17subsection (d) of this Section, may be recovered from the
18customers of the affected gas utilities, other than customers
19described in subsection (m) of this Section. The utility shall
20provide the independent program administrator with all
21information and assistance necessary to perform the program
22administrator's duties including but not limited to customer,
23account, and energy usage data, and shall allow the program
24administrator to include inserts in customer bills. The utility
25may recover reasonable costs associated with any such
26assistance.

 

 

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1    (j) No utility shall be deemed to have failed to meet the
2energy efficiency standards to the extent any such failure is
3due to a failure of the Department.
4    (k) Not later than January 1, 2012, the Commission shall
5develop and solicit public comment on a plan to foster
6statewide coordination and consistency between statutorily
7mandated natural gas and electric energy efficiency programs to
8reduce program or participant costs or to improve program
9performance. Not later than September 1, 2013, the Commission
10shall issue a report to the General Assembly containing its
11findings and recommendations.
12    (l) This Section does not apply to a gas utility that on
13January 1, 2009, provided gas service to fewer than 100,000
14customers in Illinois.
15    (m) Subsections (a) through (k) of this Section do not
16apply to customers of a natural gas utility that have a North
17American Industry Classification System code number that is
1822111 or any such code number beginning with the digits 31, 32,
19or 33 and (i) annual usage in the aggregate of 4 million therms
20or more within the service territory of the affected gas
21utility or with aggregate usage of 8 million therms or more in
22this State and complying with the provisions of item (l) of
23this subsection (m); or (ii) using natural gas as feedstock and
24meeting the usage requirements described in item (i) of this
25subsection (m), to the extent such annual feedstock usage is
26greater than 60% of the customer's total annual usage of

 

 

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1natural gas.
2        (1) Customers described in this subsection (m) of this
3    Section shall apply, on a form approved on or before
4    October 1, 2009 by the Department, to the Department to be
5    designated as a self-directing customer ("SDC") or as an
6    exempt customer using natural gas as a feedstock from which
7    other products are made, including, but not limited to,
8    feedstock for a hydrogen plant, on or before the 1st day of
9    February, 2010. Thereafter, application may be made not
10    less than 6 months before the filing date of the gas
11    utility energy efficiency plan described in subsection (f)
12    of this Section; however, a new customer that commences
13    taking service from a natural gas utility after February 1,
14    2010 may apply to become a SDC or exempt customer up to 30
15    days after beginning service. Customers described in this
16    subsection (m) that have not already been approved by the
17    Department may apply to be designated a self-directing
18    customer or exempt customer, on a form approved by the
19    Department, between September 1, 2013 and September 30,
20    2013. Customer applications that are approved by the
21    Department under this amendatory Act of the 98th General
22    Assembly shall be considered to be a self-directing
23    customer or exempt customer, as applicable, for the current
24    3-year planning period effective December 1, 2013. Such
25    application shall contain the following:
26            (A) the customer's certification that, at the time

 

 

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1        of its application, it qualifies to be a SDC or exempt
2        customer described in this subsection (m) of this
3        Section;
4            (B) in the case of a SDC, the customer's
5        certification that it has established or will
6        establish by the beginning of the utility's 3-year
7        planning period commencing subsequent to the
8        application, and will maintain for accounting
9        purposes, an energy efficiency reserve account and
10        that the customer will accrue funds in said account to
11        be held for the purpose of funding, in whole or in
12        part, energy efficiency measures of the customer's
13        choosing, which may include, but are not limited to,
14        projects involving combined heat and power systems
15        that use the same energy source both for the generation
16        of electrical or mechanical power and the production of
17        steam or another form of useful thermal energy or the
18        use of combustible gas produced from biomass, or both;
19            (C) in the case of a SDC, the customer's
20        certification that annual funding levels for the
21        energy efficiency reserve account will be equal to 2%
22        of the customer's cost of natural gas, composed of the
23        customer's commodity cost and the delivery service
24        charges paid to the gas utility, or $150,000, whichever
25        is less;
26            (D) in the case of a SDC, the customer's

 

 

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1        certification that the required reserve account
2        balance will be capped at 3 years' worth of accruals
3        and that the customer may, at its option, make further
4        deposits to the account to the extent such deposit
5        would increase the reserve account balance above the
6        designated cap level;
7            (E) in the case of a SDC, the customer's
8        certification that by October 1 of each year, beginning
9        no sooner than October 1, 2012, the customer will
10        report to the Department information, for the 12-month
11        period ending May 31 of the same year, on all deposits
12        and reductions, if any, to the reserve account during
13        the reporting year, and to the extent deposits to the
14        reserve account in any year are in an amount less than
15        $150,000, the basis for such reduced deposits; reserve
16        account balances by month; a description of energy
17        efficiency measures undertaken by the customer and
18        paid for in whole or in part with funds from the
19        reserve account; an estimate of the energy saved, or to
20        be saved, by the measure; and that the report shall
21        include a verification by an officer or plant manager
22        of the customer or by a registered professional
23        engineer or certified energy efficiency trade
24        professional that the funds withdrawn from the reserve
25        account were used for the energy efficiency measures;
26            (F) in the case of an exempt customer, the

 

 

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1        customer's certification of the level of gas usage as
2        feedstock in the customer's operation in a typical year
3        and that it will provide information establishing this
4        level, upon request of the Department;
5            (G) in the case of either an exempt customer or a
6        SDC, the customer's certification that it has provided
7        the gas utility or utilities serving the customer with
8        a copy of the application as filed with the Department;
9            (H) in the case of either an exempt customer or a
10        SDC, certification of the natural gas utility or
11        utilities serving the customer in Illinois including
12        the natural gas utility accounts that are the subject
13        of the application; and
14            (I) in the case of either an exempt customer or a
15        SDC, a verification signed by a plant manager or an
16        authorized corporate officer attesting to the
17        truthfulness and accuracy of the information contained
18        in the application.
19        (2) The Department shall review the application to
20    determine that it contains the information described in
21    provisions (A) through (I) of item (1) of this subsection
22    (m), as applicable. The review shall be completed within 30
23    days after the date the application is filed with the
24    Department. Absent a determination by the Department
25    within the 30-day period, the applicant shall be considered
26    to be a SDC or exempt customer, as applicable, for all

 

 

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1    subsequent 3-year planning periods, as of the date of
2    filing the application described in this subsection (m). If
3    the Department determines that the application does not
4    contain the applicable information described in provisions
5    (A) through (I) of item (1) of this subsection (m), it
6    shall notify the customer, in writing, of its determination
7    that the application does not contain the required
8    information and identify the information that is missing,
9    and the customer shall provide the missing information
10    within 15 working days after the date of receipt of the
11    Department's notification.
12        (3) The Department shall have the right to audit the
13    information provided in the customer's application and
14    annual reports to ensure continued compliance with the
15    requirements of this subsection. Based on the audit, if the
16    Department determines the customer is no longer in
17    compliance with the requirements of items (A) through (I)
18    of item (1) of this subsection (m), as applicable, the
19    Department shall notify the customer in writing of the
20    noncompliance. The customer shall have 30 days to establish
21    its compliance, and failing to do so, may have its status
22    as a SDC or exempt customer revoked by the Department. The
23    Department shall treat all information provided by any
24    customer seeking SDC status or exemption from the
25    provisions of this Section as strictly confidential.
26        (4) Upon request, or on its own motion, the Commission

 

 

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1    may open an investigation, no more than once every 3 years
2    and not before October 1, 2014, to evaluate the
3    effectiveness of the self-directing program described in
4    this subsection (m).
5    Customers described in this subsection (m) that applied to
6the Department on January 3, 2013, were approved by the
7Department on February 13, 2013 to be a self-directing customer
8or exempt customer, and receive natural gas from a utility that
9provides gas service to at least 500,000 retail customers in
10Illinois and electric service to at least 1,000,000 retail
11customers in Illinois shall be considered to be a
12self-directing customer or exempt customer, as applicable, for
13the current 3-year planning period effective December 1, 2013.
14    (n) The applicability of this Section to customers
15described in subsection (m) of this Section is conditioned on
16the existence of the SDC program. In no event will any
17provision of this Section apply to such customers after January
181, 2020.
19(Source: P.A. 97-813, eff. 7-13-12; 97-841, eff. 7-20-12;
2098-90, eff. 7-15-13; 98-225, eff. 8-9-13; 98-604, eff.
2112-17-13.)
 
22    (220 ILCS 5/16-107)
23    Sec. 16-107. Real-time pricing.
24    (a) Each electric utility shall file, on or before May 1,
251998, a tariff or tariffs which allow nonresidential retail

 

 

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1customers in the electric utility's service area to elect
2real-time pricing beginning October 1, 1998.
3    (b) Each electric utility shall file, on or before May 1,
42000, a tariff or tariffs which allow residential retail
5customers in the electric utility's service area to elect
6real-time pricing beginning October 1, 2000.
7    (b-5) Each electric utility shall file a tariff or tariffs
8allowing residential retail customers in the electric
9utility's service area to elect real-time pricing beginning
10January 2, 2007. A customer who elects real-time pricing shall
11remain on such rate for a minimum of 12 months. The Commission
12may, after notice and hearing, approve the tariff or tariffs,
13provided that the Commission finds that the potential for
14demand reductions will result in net economic benefits to all
15residential customers of the electric utility. In examining
16economic benefits from demand reductions, the Commission
17shall, at a minimum, consider the following: improvements to
18system reliability and power quality, reduction in wholesale
19market prices and price volatility, electric utility cost
20avoidance and reductions, market power mitigation, and other
21benefits of demand reductions, but only to the extent that the
22effects of reduced demand can be demonstrated to lower the cost
23of electricity delivered to residential customers. A tariff or
24tariffs approved pursuant to this subsection (b-5) shall, at a
25minimum, describe (i) the methodology for determining the
26market price of energy to be reflected in the real-time rate

 

 

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1and (ii) the manner in which customers who elect real-time
2pricing will be provided with ready access to hourly market
3prices, including, but not limited to, day-ahead hourly energy
4prices.
5    A proceeding under this subsection (b-5) may not exceed 120
6days in length.
7    (b-10) Each electric utility providing real-time pricing
8pursuant to subsection (b-5) shall install a meter capable of
9recording hourly interval energy use at the service location of
10each customer that elects real-time pricing pursuant to this
11subsection.
12    (b-15) If the Commission issues an order pursuant to
13subsection (b-5), the affected electric utility shall contract
14with an entity not affiliated with the electric utility to
15serve as a program administrator to develop and implement a
16program to provide consumer outreach, enrollment, and
17education concerning real-time pricing and to establish and
18administer an information system and technical and other
19customer assistance that is necessary to enable customers to
20manage electricity use. The program administrator: (i) shall be
21selected and compensated by the electric utility, subject to
22Commission approval; (ii) shall have demonstrated technical
23and managerial competence in the development and
24administration of demand management programs; and (iii) may
25develop and implement risk management, energy efficiency, and
26other services related to energy use management for which the

 

 

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1program administrator shall be compensated by participants in
2the program receiving such services. The electric utility shall
3provide the program administrator with all information and
4assistance necessary to perform the program administrator's
5duties, including, but not limited to, customer, account, and
6energy use data. The electric utility shall permit the program
7administrator to include inserts in residential customer bills
82 times per year to assist with customer outreach and
9enrollment.
10    The program administrator shall submit an annual report to
11the electric utility no later than April 1 of each year
12describing the operation and results of the program, including
13information concerning the number and types of customers using
14real-time pricing, changes in customers' energy use patterns,
15an assessment of the value of the program to both participants
16and non-participants, and recommendations concerning
17modification of the program and the tariff or tariffs filed
18under subsection (b-5). This report shall be filed by the
19electric utility with the Commission within 30 days of receipt
20and shall be available to the public on the Commission's web
21site.
22    (b-20) The Commission shall monitor the performance of
23programs established pursuant to subsection (b-15) and shall
24order the termination or modification of a program if it
25determines that the program is not, after a reasonable period
26of time for development not to exceed 4 years, resulting in net

 

 

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1benefits to the residential customers of the electric utility.
2    (b-25) An electric utility shall be entitled to recover
3reasonable costs incurred in complying with this Section,
4provided that recovery of the costs is fairly apportioned among
5its residential customers as provided in this subsection
6(b-25). The electric utility may apportion greater costs on the
7residential customers who elect real-time pricing, but may also
8impose some of the costs of real-time pricing on customers who
9do not elect real-time pricing, provided that the Commission
10determines that the cost savings resulting from real-time
11pricing will exceed the costs imposed on customers for
12maintaining the program.
13    (c) The electric utility's tariff or tariffs filed pursuant
14to this Section shall be subject to Article IX.
15    (d) This Section does not apply to any electric utility
16providing service to 100,000 or fewer customers.
17(Source: P.A. 94-977, eff. 6-30-06.)
 
18    (220 ILCS 5/16-108.5)
19    Sec. 16-108.5. Infrastructure investment and
20modernization; regulatory reform.
21    (a) (Blank).
22    (b) For purposes of this Section, "participating utility"
23means an electric utility or a combination utility serving more
24than 1,000,000 customers in Illinois that voluntarily elects
25and commits to undertake (i) the infrastructure investment

 

 

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1program consisting of the commitments and obligations
2described in this subsection (b) and (ii) the customer
3assistance program consisting of the commitments and
4obligations described in subsection (b-10) of this Section,
5notwithstanding any other provisions of this Act and without
6obtaining any approvals from the Commission or any other agency
7other than as set forth in this Section, regardless of whether
8any such approval would otherwise be required. "Combination
9utility" means a utility that, as of January 1, 2011, provided
10electric service to at least one million retail customers in
11Illinois and gas service to at least 500,000 retail customers
12in Illinois. A participating utility shall recover the
13expenditures made under the infrastructure investment program
14through the ratemaking process, including, but not limited to,
15the performance-based formula rate and process set forth in
16this Section.
17    During the infrastructure investment program's peak
18program year, a participating utility other than a combination
19utility shall create 2,000 full-time equivalent jobs in
20Illinois, and a participating utility that is a combination
21utility shall create 450 full-time equivalent jobs in Illinois
22related to the provision of electric service. These jobs shall
23include direct jobs, contractor positions, and induced jobs,
24but shall not include any portion of a job commitment, not
25specifically contingent on an amendatory Act of the 97th
26General Assembly becoming law, between a participating utility

 

 

HB2607- 136 -LRB099 06217 AMC 30868 b

1and a labor union that existed on the effective date of this
2amendatory Act of the 97th General Assembly and that has not
3yet been fulfilled. A portion of the full-time equivalent jobs
4created by each participating utility shall include
5incremental personnel hired subsequent to the effective date of
6this amendatory Act of the 97th General Assembly. For purposes
7of this Section, "peak program year" means the consecutive
812-month period with the highest number of full-time equivalent
9jobs that occurs between the beginning of investment year 2 and
10the end of investment year 4.
11    A participating utility shall meet one of the following
12commitments, as applicable:
13        (1) Beginning no later than 180 days after a
14    participating utility other than a combination utility
15    files a performance-based formula rate tariff pursuant to
16    subsection (c) of this Section, or, beginning no later than
17    January 1, 2012 if such utility files such
18    performance-based formula rate tariff within 14 days of the
19    effective date of this amendatory Act of the 97th General
20    Assembly, the participating utility shall, except as
21    provided in subsection (b-5):
22            (A) over a 5-year period, invest an estimated
23        $1,300,000,000 in electric system upgrades,
24        modernization projects, and training facilities,
25        including, but not limited to:
26                (i) distribution infrastructure improvements

 

 

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1            totaling an estimated $1,000,000,000, including
2            underground residential distribution cable
3            injection and replacement and mainline cable
4            system refurbishment and replacement projects;
5                (ii) training facility construction or upgrade
6            projects totaling an estimated $10,000,000,
7            provided that, at a minimum, one such facility
8            shall be located in a municipality having a
9            population of more than 2 million residents and one
10            such facility shall be located in a municipality
11            having a population of more than 150,000 residents
12            but fewer than 170,000 residents; any such new
13            facility located in a municipality having a
14            population of more than 2 million residents must be
15            designed for the purpose of obtaining, and the
16            owner of the facility shall apply for,
17            certification under the United States Green
18            Building Council's Leadership in Energy Efficiency
19            Design Green Building Rating System;
20                (iii) wood pole inspection, treatment, and
21            replacement programs;
22                (iv) an estimated $200,000,000 for reducing
23            the susceptibility of certain circuits to
24            storm-related damage, including, but not limited
25            to, high winds, thunderstorms, and ice storms;
26            improvements may include, but are not limited to,

 

 

HB2607- 138 -LRB099 06217 AMC 30868 b

1            overhead to underground conversion and other
2            engineered outcomes for circuits; the
3            participating utility shall prioritize the
4            selection of circuits based on each circuit's
5            historical susceptibility to storm-related damage
6            and the ability to provide the greatest customer
7            benefit upon completion of the improvements; to be
8            eligible for improvement, the participating
9            utility's ability to maintain proper tree
10            clearances surrounding the overhead circuit must
11            not have been impeded by third parties; and
12            (B) over a 10-year period, invest an estimated
13        $1,300,000,000 to upgrade and modernize its
14        transmission and distribution infrastructure and in
15        Smart Grid electric system upgrades, including, but
16        not limited to:
17                (i) additional smart meters;
18                (ii) distribution automation;
19                (iii) associated cyber secure data
20            communication network; and
21                (iv) substation micro-processor relay
22            upgrades.
23        (2) Beginning no later than 180 days after a
24    participating utility that is a combination utility files a
25    performance-based formula rate tariff pursuant to
26    subsection (c) of this Section, or, beginning no later than

 

 

HB2607- 139 -LRB099 06217 AMC 30868 b

1    January 1, 2012 if such utility files such
2    performance-based formula rate tariff within 14 days of the
3    effective date of this amendatory Act of the 97th General
4    Assembly, the participating utility shall, except as
5    provided in subsection (b-5):
6            (A) over a 10-year period, invest an estimated
7        $265,000,000 in electric system upgrades,
8        modernization projects, and training facilities,
9        including, but not limited to:
10                (i) distribution infrastructure improvements
11            totaling an estimated $245,000,000, which may
12            include bulk supply substations, transformers,
13            reconductoring, and rebuilding overhead
14            distribution and sub-transmission lines,
15            underground residential distribution cable
16            injection and replacement and mainline cable
17            system refurbishment and replacement projects;
18                (ii) training facility construction or upgrade
19            projects totaling an estimated $1,000,000; any
20            such new facility must be designed for the purpose
21            of obtaining, and the owner of the facility shall
22            apply for, certification under the United States
23            Green Building Council's Leadership in Energy
24            Efficiency Design Green Building Rating System;
25            and
26                (iii) wood pole inspection, treatment, and

 

 

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1            replacement programs; and
2            (B) over a 10-year period, invest an estimated
3        $360,000,000 to upgrade and modernize its transmission
4        and distribution infrastructure and in Smart Grid
5        electric system upgrades, including, but not limited
6        to:
7                (i) additional smart meters;
8                (ii) distribution automation;
9                (iii) associated cyber secure data
10            communication network; and
11                (iv) substation micro-processor relay
12            upgrades.
13    For purposes of this Section, "Smart Grid electric system
14upgrades" shall have the meaning set forth in subsection (a) of
15Section 16-108.6 of this Act.
16    The investments in the infrastructure investment program
17described in this subsection (b) shall be incremental to the
18participating utility's annual capital investment program, as
19defined by, for purposes of this subsection (b), the
20participating utility's average capital spend for calendar
21years 2008, 2009, and 2010 as reported in the applicable
22Federal Energy Regulatory Commission (FERC) Form 1; provided
23that where one or more utilities have merged, the average
24capital spend shall be determined using the aggregate of the
25merged utilities' capital spend reported in FERC Form 1 for the
26years 2008, 2009, and 2010. A participating utility may add

 

 

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1reasonable construction ramp-up and ramp-down time to the
2investment periods specified in this subsection (b). For each
3such investment period, the ramp-up and ramp-down time shall
4not exceed a total of 6 months.
5    Within 60 days after filing a tariff under subsection (c)
6of this Section, a participating utility shall submit to the
7Commission its plan, including scope, schedule, and staffing,
8for satisfying its infrastructure investment program
9commitments pursuant to this subsection (b). The submitted plan
10shall include a schedule and staffing plan for the next
11calendar year. The plan shall also include a plan for the
12creation, operation, and administration of a Smart Grid test
13bed as described in subsection (c) of Section 16-108.8. The
14plan need not allocate the work equally over the respective
15periods, but should allocate material increments throughout
16such periods commensurate with the work to be undertaken. No
17later than April 1 of each subsequent year, the utility shall
18submit to the Commission a report that includes any updates to
19the plan, a schedule for the next calendar year, the
20expenditures made for the prior calendar year and cumulatively,
21and the number of full-time equivalent jobs created for the
22prior calendar year and cumulatively. If the utility is
23materially deficient in satisfying a schedule or staffing plan,
24then the report must also include a corrective action plan to
25address the deficiency. The fact that the plan, implementation
26of the plan, or a schedule changes shall not imply the

 

 

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1imprudence or unreasonableness of the infrastructure
2investment program, plan, or schedule. Further, no later than
345 days following the last day of the first, second, and third
4quarters of each year of the plan, a participating utility
5shall submit to the Commission a verified quarterly report for
6the prior quarter that includes (i) the total number of
7full-time equivalent jobs created during the prior quarter,
8(ii) the total number of employees as of the last day of the
9prior quarter, (iii) the total number of full-time equivalent
10hours in each job classification or job title, (iv) the total
11number of incremental employees and contractors in support of
12the investments undertaken pursuant to this subsection (b) for
13the prior quarter, and (v) any other information that the
14Commission may require by rule.
15    With respect to the participating utility's peak job
16commitment, if, after considering the utility's corrective
17action plan and compliance thereunder, the Commission enters an
18order finding, after notice and hearing, that a participating
19utility did not satisfy its peak job commitment described in
20this subsection (b) for reasons that are reasonably within its
21control, then the Commission shall also determine, after
22consideration of the evidence, including, but not limited to,
23evidence submitted by the Department of Commerce and Economic
24Opportunity and the utility, the deficiency in the number of
25full-time equivalent jobs during the peak program year due to
26such failure. The Commission shall notify the Department of any

 

 

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

 

 

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

 

 

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

 

 

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1not to exceed the limitation imposed by this subsection (b-5)
2and may propose corresponding changes to the metrics
3established pursuant to subparagraphs (5) through (8) of
4subsection (f) of this Section, and the Commission may modify
5the metrics and incremental savings goals established pursuant
6to subsection (f) of this Section accordingly.
7    (b-10) All participating utilities shall make
8contributions for an energy low-income and support program in
9accordance with this subsection. Beginning no later than 180
10days after a participating utility files a performance-based
11formula rate tariff pursuant to subsection (c) of this Section,
12or beginning no later than January 1, 2012 if such utility
13files such performance-based formula rate tariff within 14 days
14of the effective date of this amendatory Act of the 97th
15General Assembly, and without obtaining any approvals from the
16Commission or any other agency other than as set forth in this
17Section, regardless of whether any such approval would
18otherwise be required, a participating utility other than a
19combination utility shall pay $10,000,000 per year for 5 years
20and a participating utility that is a combination utility shall
21pay $1,000,000 per year for 10 years to the energy low-income
22and support program, which is intended to fund customer
23assistance programs with the primary purpose being avoidance of
24imminent disconnection. Such programs may include:
25        (1) a residential hardship program that may partner
26    with community-based organizations, including senior

 

 

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1    citizen organizations, and provides grants to low-income
2    residential customers, including low-income senior
3    citizens, who demonstrate a hardship;
4        (2) a program that provides grants and other bill
5    payment concessions to disabled veterans who demonstrate a
6    hardship and members of the armed services or reserve
7    forces of the United States or members of the Illinois
8    National Guard who are on active duty pursuant to an
9    executive order of the President of the United States, an
10    act of the Congress of the United States, or an order of
11    the Governor and who demonstrate a hardship;
12        (3) a budget assistance program that provides tools and
13    education to low-income senior citizens to assist them with
14    obtaining information regarding energy usage and effective
15    means of managing energy costs;
16        (4) a non-residential special hardship program that
17    provides grants to non-residential customers such as small
18    businesses and non-profit organizations that demonstrate a
19    hardship, including those providing services to senior
20    citizen and low-income customers; and
21        (5) a performance-based assistance program that
22    provides grants to encourage residential customers to make
23    on-time payments by matching a portion of the customer's
24    payments or providing credits towards arrearages.
25    The payments made by a participating utility pursuant to
26this subsection (b-10) shall not be a recoverable expense. A

 

 

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1participating utility may elect to fund either new or existing
2customer assistance programs, including, but not limited to,
3those that are administered by the utility.
4    Programs that use funds that are provided by a
5participating utility to reduce utility bills shall may be
6implemented through tariffs that are filed with and reviewed by
7the Commission. If a utility elects to file tariffs with the
8Commission to implement all or a portion of the programs, those
9tariffs shall, regardless of the date actually filed, be deemed
10accepted and approved, and shall become effective on the
11effective date of this amendatory Act of the 97th General
12Assembly. The participating utilities whose customers benefit
13from the funds that are disbursed as contemplated in this
14Section shall file annual reports documenting the disbursement
15of those funds with the Commission. The Commission has the
16authority to audit disbursement of the funds to ensure they
17were disbursed consistently with this Section.
18    If the Commission finds that a participating utility is no
19longer eligible to update the performance-based formula rate
20tariff pursuant to subsection (d) of this Section, or the
21performance-based formula rate is otherwise terminated, then
22the participating utility's voluntary commitments and
23obligations under this subsection (b-10) shall immediately
24terminate.
25    (c) A participating utility shall may elect to recover its
26delivery services costs through a performance-based formula

 

 

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1rate approved by the Commission, which shall specify the cost
2components that form the basis of the rate charged to customers
3with sufficient specificity to operate in a standardized manner
4and be updated annually with transparent information that
5reflects the utility's actual costs to be recovered during the
6applicable rate year, which is the period beginning with the
7first billing day of January and extending through the last
8billing day of the following December. In the event the utility
9recovers a portion of its costs through automatic adjustment
10clause tariffs on the effective date of this amendatory Act of
11the 97th General Assembly, the utility may elect to continue to
12recover these costs through such tariffs, but then these costs
13shall not be recovered through the performance-based formula
14rate. In the event the participating utility, prior to the
15effective date of this amendatory Act of the 97th General
16Assembly, filed electric delivery services tariffs with the
17Commission pursuant to Section 9-201 of this Act that are
18related to the recovery of its electric delivery services costs
19that are still pending on the effective date of this amendatory
20Act of the 97th General Assembly, the participating utility
21shall, at the time it files its performance-based formula rate
22tariff with the Commission, also file a notice of withdrawal
23with the Commission to withdraw the electric delivery services
24tariffs previously filed pursuant to Section 9-201 of this Act.
25Upon receipt of such notice, the Commission shall dismiss with
26prejudice any docket that had been initiated to investigate the

 

 

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1electric delivery services tariffs filed pursuant to Section
29-201 of this Act, and such tariffs and the record related
3thereto shall not be the subject of any further hearing,
4investigation, or proceeding of any kind related to rates for
5electric delivery services.
6    The performance-based formula rate shall be implemented
7through a tariff filed with the Commission consistent with the
8provisions of this subsection (c) that shall be applicable to
9all delivery services customers. The Commission shall initiate
10and conduct an investigation of the tariff in a manner
11consistent with the provisions of this subsection (c) and the
12provisions of Article IX of this Act to the extent they do not
13conflict with this subsection (c). Except in the case where the
14Commission finds, after notice and hearing, that a
15participating utility is not satisfying its investment amount
16commitments under subsection (b) of this Section, the
17performance-based formula rate shall remain in effect at the
18discretion of the utility. The performance-based formula rate
19approved by the Commission shall do the following:
20        (1) Provide for the recovery of the utility's actual
21    costs of delivery services that are prudently incurred and
22    reasonable in amount consistent with Commission practice
23    and law. The sole fact that a cost differs from that
24    incurred in a prior calendar year or that an investment is
25    different from that made in a prior calendar year shall not
26    imply the imprudence or unreasonableness of that cost or

 

 

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1    investment.
2        (2) Reflect the utility's actual year-end capital
3    structure for the applicable calendar year, excluding
4    goodwill, subject to a determination of prudence and
5    reasonableness consistent with Commission practice and
6    law.
7        (3) Include a cost of equity, which shall be calculated
8    as the sum of the following:
9            (A) the average for the applicable calendar year of
10        the monthly average yields of 30-year U.S. Treasury
11        bonds published by the Board of Governors of the
12        Federal Reserve System in its weekly H.15 Statistical
13        Release or successor publication; and
14            (B) 580 basis points.
15        At such time as the Board of Governors of the Federal
16    Reserve System ceases to include the monthly average yields
17    of 30-year U.S. Treasury bonds in its weekly H.15
18    Statistical Release or successor publication, the monthly
19    average yields of the U.S. Treasury bonds then having the
20    longest duration published by the Board of Governors in its
21    weekly H.15 Statistical Release or successor publication
22    shall instead be used for purposes of this paragraph (3).
23        (4) Permit and set forth protocols, subject to a
24    determination of prudence and reasonableness consistent
25    with Commission practice and law, for the following:
26            (A) recovery of incentive compensation expense

 

 

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1        that is based on the achievement of operational
2        metrics, including metrics related to budget controls,
3        outage duration and frequency, safety, customer
4        service, efficiency and productivity, and
5        environmental compliance. Incentive compensation
6        expense that is based on net income or an affiliate's
7        earnings per share shall not be recoverable under the
8        performance-based formula rate;
9            (B) recovery of pension and other post-employment
10        benefits expense, provided that such costs are
11        supported by an actuarial study;
12            (C) recovery of severance costs, provided that if
13        the amount is over $3,700,000 for a participating
14        utility that is a combination utility or $10,000,000
15        for a participating utility that serves more than 3
16        million retail customers, then the full amount shall be
17        amortized consistent with subparagraph (F) of this
18        paragraph (4);
19            (D) investment return at a rate equal to the
20        utility's weighted average cost of long-term debt, on
21        the pension assets as, and in the amount, reported in
22        Account 186 (or in such other Account or Accounts as
23        such asset may subsequently be recorded) of the
24        utility's most recently filed FERC Form 1, net of
25        deferred tax benefits;
26            (E) recovery of the expenses related to the

 

 

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1        Commission proceeding under this subsection (c) to
2        approve this performance-based formula rate and
3        initial rates or to subsequent proceedings related to
4        the formula, provided that the recovery shall be
5        amortized over a 3-year period; recovery of expenses
6        related to the annual Commission proceedings under
7        subsection (d) of this Section to review the inputs to
8        the performance-based formula rate shall be expensed
9        and recovered through the performance-based formula
10        rate;
11            (F) amortization over a 5-year period of the full
12        amount of each charge or credit that exceeds $3,700,000
13        for a participating utility that is a combination
14        utility or $10,000,000 for a participating utility
15        that serves more than 3 million retail customers in the
16        applicable calendar year and that relates to a
17        workforce reduction program's severance costs, changes
18        in accounting rules, changes in law, compliance with
19        any Commission-initiated audit, or a single storm or
20        other similar expense, provided that any unamortized
21        balance shall be reflected in rate base. For purposes
22        of this subparagraph (F), changes in law includes any
23        enactment, repeal, or amendment in a law, ordinance,
24        rule, regulation, interpretation, permit, license,
25        consent, or order, including those relating to taxes,
26        accounting, or to environmental matters, or in the

 

 

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1        interpretation or application thereof by any
2        governmental authority occurring after the effective
3        date of this amendatory Act of the 97th General
4        Assembly;
5            (G) recovery of existing regulatory assets over
6        the periods previously authorized by the Commission;
7            (H) historical weather normalized billing
8        determinants; and
9            (I) allocation methods for common costs.
10        (5) Provide that if the participating utility's earned
11    rate of return on common equity related to the provision of
12    delivery services for the prior rate year (calculated using
13    costs and capital structure approved by the Commission as
14    provided in subparagraph (2) of this subsection (c),
15    consistent with this Section, in accordance with
16    Commission rules and orders, including, but not limited to,
17    adjustments for goodwill, and after any Commission-ordered
18    disallowances and taxes) is more than 50 basis points
19    higher than the rate of return on common equity calculated
20    pursuant to paragraph (3) of this subsection (c) (after
21    adjusting for any penalties to the rate of return on common
22    equity applied pursuant to the performance metrics
23    provision of subsection (f) of this Section), then the
24    participating utility shall apply a credit through the
25    performance-based formula rate that reflects an amount
26    equal to the value of that portion of the earned rate of

 

 

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

 

 

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1    adjusting for any penalties to the rate of return on common
2    equity applied pursuant to the performance metrics
3    provision of subsection (f) of this Section) for the prior
4    rate year, adjusted for taxes.
5        (6) Provide for an annual reconciliation, as described
6    in subsection (d) of this Section, with interest, of the
7    revenue requirement reflected in rates for each calendar
8    year, beginning with the calendar year in which the utility
9    files its performance-based formula rate tariff pursuant
10    to subsection (c) of this Section, with what the revenue
11    requirement would have been had the actual cost information
12    for the applicable calendar year been available at the
13    filing date.
14    The utility shall file, together with its tariff, final
15data based on its most recently filed FERC Form 1, plus
16projected plant additions and correspondingly updated
17depreciation reserve and expense for the calendar year in which
18the tariff and data are filed, that shall populate the
19performance-based formula rate and set the initial delivery
20services rates under the formula. For purposes of this Section,
21"FERC Form 1" means the Annual Report of Major Electric
22Utilities, Licensees and Others that electric utilities are
23required to file with the Federal Energy Regulatory Commission
24under the Federal Power Act, Sections 3, 4(a), 304 and 209,
25modified as necessary to be consistent with 83 Ill. Admin. Code
26Part 415 as of May 1, 2011. Nothing in this Section is intended

 

 

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1to allow costs that are not otherwise recoverable to be
2recoverable by virtue of inclusion in FERC Form 1.
3    After the utility files its proposed performance-based
4formula rate structure and protocols and initial rates, the
5Commission shall initiate a docket to review the filing. The
6Commission shall enter an order approving, or approving as
7modified, the performance-based formula rate, including the
8initial rates, as just and reasonable within 270 days after the
9date on which the tariff was filed, or, if the tariff is filed
10within 14 days after the effective date of this amendatory Act
11of the 97th General Assembly, then by May 31, 2012. Such review
12shall be based on the same evidentiary standards, including,
13but not limited to, those concerning the prudence and
14reasonableness of the costs incurred by the utility, the
15Commission applies in a hearing to review a filing for a
16general increase in rates under Article IX of this Act. The
17initial rates shall take effect within 30 days after the
18Commission's order approving the performance-based formula
19rate tariff.
20    Until such time as the Commission approves a different rate
21design and cost allocation pursuant to subsection (e) of this
22Section, rate design and cost allocation across customer
23classes shall be consistent with the Commission's most recent
24order regarding the participating utility's request for a
25general increase in its delivery services rates.
26    Subsequent changes to the performance-based formula rate

 

 

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1structure or protocols shall be made as set forth in Section
29-201 of this Act, but nothing in this subsection (c) is
3intended to limit the Commission's authority under Article IX
4and other provisions of this Act to initiate an investigation
5of a participating utility's performance-based formula rate
6tariff, provided that any such changes shall be consistent with
7paragraphs (1) through (6) of this subsection (c). Any change
8ordered by the Commission shall be made at the same time new
9rates take effect following the Commission's next order
10pursuant to subsection (d) of this Section, provided that the
11new rates take effect no less than 30 days after the date on
12which the Commission issues an order adopting the change.
13    A participating utility that files a tariff pursuant to
14this subsection (c) must submit a one-time $200,000 filing fee
15at the time the Chief Clerk of the Commission accepts the
16filing, which shall be a recoverable expense.
17    In the event the performance-based formula rate is
18terminated, the then current rates shall remain in effect until
19such time as new rates are set pursuant to Article IX of this
20Act, subject to retroactive rate adjustment, with interest, to
21reconcile rates charged with actual costs. At such time that
22the performance-based formula rate is terminated, the
23participating utility's voluntary commitments and obligations
24under subsection (b) of this Section shall immediately
25terminate, except for the utility's obligation to pay an amount
26already owed to the fund for training grants pursuant to a

 

 

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1Commission order issued under subsection (b) of this Section.
2    (d) Subsequent to the Commission's issuance of an order
3approving the utility's performance-based formula rate
4structure and protocols, and initial rates under subsection (c)
5of this Section, the utility shall file, on or before May 1 of
6each year, with the Chief Clerk of the Commission its updated
7cost inputs to the performance-based formula rate for the
8applicable rate year and the corresponding new charges. Each
9such filing shall conform to the following requirements and
10include the following information:
11        (1) The inputs to the performance-based formula rate
12    for the applicable rate year shall be based on final
13    historical data reflected in the utility's most recently
14    filed annual FERC Form 1 plus projected plant additions and
15    correspondingly updated depreciation reserve and expense
16    for the calendar year in which the inputs are filed. The
17    filing shall also include a reconciliation of the revenue
18    requirement that was in effect for the prior rate year (as
19    set by the cost inputs for the prior rate year) with the
20    actual revenue requirement for the prior rate year
21    (determined using a year-end rate base) that uses amounts
22    reflected in the applicable FERC Form 1 that reports the
23    actual costs for the prior rate year. Any over-collection
24    or under-collection indicated by such reconciliation shall
25    be reflected as a credit against, or recovered as an
26    additional charge to, respectively, with interest

 

 

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1    calculated at a rate equal to the utility's weighted
2    average cost of capital approved by the Commission for the
3    prior rate year, the charges for the applicable rate year.
4    Provided, however, that the first such reconciliation
5    shall be for the calendar year in which the utility files
6    its performance-based formula rate tariff pursuant to
7    subsection (c) of this Section and shall reconcile (i) the
8    revenue requirement or requirements established by the
9    rate order or orders in effect from time to time during
10    such calendar year (weighted, as applicable) with (ii) the
11    revenue requirement determined using a year-end rate base
12    for that calendar year calculated pursuant to the
13    performance-based formula rate using (A) actual costs for
14    that year as reflected in the applicable FERC Form 1, and
15    (B) for the first such reconciliation only, the cost of
16    equity, which shall be calculated as the sum of 590 basis
17    points plus the average for the applicable calendar year of
18    the monthly average yields of 30-year U.S. Treasury bonds
19    published by the Board of Governors of the Federal Reserve
20    System in its weekly H.15 Statistical Release or successor
21    publication. The first such reconciliation is not intended
22    to provide for the recovery of costs previously excluded
23    from rates based on a prior Commission order finding of
24    imprudence or unreasonableness. Each reconciliation shall
25    be certified by the participating utility in the same
26    manner that FERC Form 1 is certified. The filing shall also

 

 

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1    include the charge or credit, if any, resulting from the
2    calculation required by paragraph (6) of subsection (c) of
3    this Section.
4        Notwithstanding anything that may be to the contrary,
5    the intent of the reconciliation is to ultimately reconcile
6    the revenue requirement reflected in rates for each
7    calendar year, beginning with the calendar year in which
8    the utility files its performance-based formula rate
9    tariff pursuant to subsection (c) of this Section, with
10    what the revenue requirement determined using a year-end
11    rate base for the applicable calendar year would have been
12    had the actual cost information for the applicable calendar
13    year been available at the filing date.
14        (2) The new charges shall take effect beginning on the
15    first billing day of the following January billing period
16    and remain in effect through the last billing day of the
17    next December billing period regardless of whether the
18    Commission enters upon a hearing pursuant to this
19    subsection (d).
20        (3) The filing shall include relevant and necessary
21    data and documentation for the applicable rate year that is
22    consistent with the Commission's rules applicable to a
23    filing for a general increase in rates or any rules adopted
24    by the Commission to implement this Section. Normalization
25    adjustments shall not be required. Notwithstanding any
26    other provision of this Section or Act or any rule or other

 

 

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

 

 

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1proceeding under this subsection (d) to consider or order any
2changes to the structure or protocols of the performance-based
3formula rate approved pursuant to subsection (c) of this
4Section. In a proceeding under this subsection (d), the
5Commission shall enter its order no later than the earlier of
6240 days after the utility's filing of its annual update of
7cost inputs to the performance-based formula rate or December
831. The Commission's determinations of the prudence and
9reasonableness of the costs incurred for the applicable
10calendar year shall be final upon entry of the Commission's
11order and shall not be subject to reopening, reexamination, or
12collateral attack in any other Commission proceeding, case,
13docket, order, rule or regulation, provided, however, that
14nothing in this subsection (d) shall prohibit a party from
15petitioning the Commission to rehear or appeal to the courts
16the order pursuant to the provisions of this Act.
17    In the event the Commission does not, either upon complaint
18or its own initiative, enter upon a hearing within 45 days
19after the utility files the annual update of cost inputs to its
20performance-based formula rate, then the costs incurred for the
21applicable calendar year shall be deemed prudent and
22reasonable, and the filed charges shall not be subject to
23reopening, reexamination, or collateral attack in any other
24proceeding, case, docket, order, rule, or regulation.
25    A participating utility's first filing of the updated cost
26inputs, and any Commission investigation of such inputs

 

 

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1pursuant to this subsection (d) shall proceed notwithstanding
2the fact that the Commission's investigation under subsection
3(c) of this Section is still pending and notwithstanding any
4other law, order, rule, or Commission practice to the contrary.
5    (e) Nothing in subsections (c) or (d) of this Section shall
6prohibit the Commission from investigating, or a participating
7utility from filing, revenue-neutral tariff changes related to
8rate design of a performance-based formula rate that has been
9placed into effect for the utility. Following approval of a
10participating utility's performance-based formula rate tariff
11pursuant to subsection (c) of this Section, the utility shall
12make a filing with the Commission within one year after the
13effective date of the performance-based formula rate tariff
14that proposes changes to the tariff to incorporate the findings
15of any final rate design orders of the Commission applicable to
16the participating utility and entered subsequent to the
17Commission's approval of the tariff. The Commission shall,
18after notice and hearing, enter its order approving, or
19approving with modification, the proposed changes to the
20performance-based formula rate tariff within 240 days after the
21utility's filing. Following such approval, the utility shall
22make a filing with the Commission during each subsequent 3-year
23period that either proposes revenue-neutral tariff changes or
24re-files the existing tariffs without change, which shall
25present the Commission with an opportunity to suspend the
26tariffs and consider revenue-neutral tariff changes related to

 

 

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1rate design.
2    (f) Within 30 days after the filing of a tariff pursuant to
3subsection (c) of this Section, each participating utility
4shall develop and file with the Commission multi-year metrics
5designed to achieve, ratably (i.e., in equal segments) over a
610-year period, improvement over baseline performance values
7as follows:
8        (1) Twenty percent improvement in the System Average
9    Interruption Frequency Index, using a baseline of the
10    average of the data from 2001 through 2010.
11        (2) Fifteen percent improvement in the system Customer
12    Average Interruption Duration Index, using a baseline of
13    the average of the data from 2001 through 2010.
14        (3) For a participating utility other than a
15    combination utility, 20% improvement in the System Average
16    Interruption Frequency Index for its Southern Region,
17    using a baseline of the average of the data from 2001
18    through 2010. For purposes of this paragraph (3), Southern
19    Region shall have the meaning set forth in the
20    participating utility's most recent report filed pursuant
21    to Section 16-125 of this Act.
22        (3.5) For a participating utility other than a
23    combination utility, 20% improvement in the System Average
24    Interruption Frequency Index for its Northeastern Region,
25    using a baseline of the average of the data from 2001
26    through 2010. For purposes of this paragraph (3.5),

 

 

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1    Northeastern Region shall have the meaning set forth in the
2    participating utility's most recent report filed pursuant
3    to Section 16-125 of this Act.
4        (4) Seventy-five percent improvement in the total
5    number of customers who exceed the service reliability
6    targets as set forth in subparagraphs (A) through (C) of
7    paragraph (4) of subsection (b) of 83 Ill. Admin. Code Part
8    411.140 as of May 1, 2011, using 2010 as the baseline year.
9        (5) Reduction in issuance of estimated electric bills:
10    90% improvement for a participating utility other than a
11    combination utility, and 56% improvement for a
12    participating utility that is a combination utility, using
13    a baseline of the average number of estimated bills for the
14    years 2008 through 2010.
15        (6) Consumption on inactive meters: 90% improvement
16    for a participating utility other than a combination
17    utility, and 56% improvement for a participating utility
18    that is a combination utility, using a baseline of the
19    average unbilled kilowatthours for the years 2009 and 2010.
20        (7) Unaccounted for energy: 50% improvement for a
21    participating utility other than a combination utility
22    using a baseline of the non-technical line loss unaccounted
23    for energy kilowatthours for the year 2009.
24        (8) Uncollectible expense: reduce uncollectible
25    expense by at least $30,000,000 for a participating utility
26    other than a combination utility and by at least $3,500,000

 

 

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1    for a participating utility that is a combination utility,
2    using a baseline of the average uncollectible expense for
3    the years 2008 through 2010.
4        (9) Opportunities for minority-owned and female-owned
5    business enterprises: design a performance metric
6    regarding the creation of opportunities for minority-owned
7    and female-owned business enterprises consistent with
8    State and federal law using a base performance value of the
9    percentage of the participating utility's capital
10    expenditures that were paid to minority-owned and
11    female-owned business enterprises in 2010.
12        (10) Achieving cost-effective energy efficiency
13    savings consistent with Section 8-103 of this Act. By
14    January 1, 2018, each participating utility shall file with
15    the Commission a proposed set of performance metrics
16    designed to align financial rewards with the utility's
17    performance relative to the goal provided in Section 8-103
18    of this Act.
19        (11) Improve load shape by achieving a 20% reduction in
20    peak load by January 1, 2025 as compared to the baseline
21    year of 2009 through annual incremental reductions.
22    The definitions set forth in 83 Ill. Admin. Code Part
23411.20 as of May 1, 2011 shall be used for purposes of
24calculating performance under paragraphs (1) through (3.5) of
25this subsection (f), provided, however, that the participating
26utility may exclude up to 9 extreme weather event days from

 

 

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1such calculation for each year, and provided further that the
2participating utility shall exclude 9 extreme weather event
3days when calculating each year of the baseline period to the
4extent that there are 9 such days in a given year of the
5baseline period. For purposes of this Section, an extreme
6weather event day is a 24-hour calendar day (beginning at 12:00
7a.m. and ending at 11:59 p.m.) during which any weather event
8(e.g., storm, tornado) caused interruptions for 10,000 or more
9of the participating utility's customers for 3 hours or more.
10If there are more than 9 extreme weather event days in a year,
11then the utility may choose no more than 9 extreme weather
12event days to exclude, provided that the same extreme weather
13event days are excluded from each of the calculations performed
14under paragraphs (1) through (3.5) of this subsection (f).
15    The metrics shall include incremental performance goals
16for each year of the 10-year period, which shall be designed to
17demonstrate that the utility is on track to achieve the
18performance goal in each category at the end of the 10-year
19period. The utility shall elect when the 10-year period shall
20commence for the metrics set forth in subparagraphs (1) through
21(4) and (9) of this subsection (f), provided that it begins no
22later than 14 months following the date on which the utility
23begins investing pursuant to subsection (b) of this Section,
24and when the 10-year period shall commence for the metrics set
25forth in subparagraphs (5) through (8) of this subsection (f),
26provided that it begins no later than 14 months following the

 

 

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1date on which the Commission enters its order approving the
2utility's Advanced Metering Infrastructure Deployment Plan
3pursuant to subsection (c) of Section 16-108.6 of this Act.
4    The metrics and performance goals set forth in
5subparagraphs (5) through (8) of this subsection (f) are based
6on the assumptions that the participating utility may fully
7implement the technology described in subsection (b) of this
8Section, including utilizing the full functionality of such
9technology and that there is no requirement for personal
10on-site notification. If the utility is unable to meet the
11metrics and performance goals set forth in subparagraphs (5)
12through (8) of this subsection (f) for such reasons, and the
13Commission so finds after notice and hearing, then the utility
14shall be excused from compliance, but only to the limited
15extent achievement of the affected metrics and performance
16goals was hindered by the less than full implementation.
17    (f-5) The financial penalties applicable to the metrics
18described in subparagraphs (1) through (8) of subsection (f) of
19this Section, as applicable, shall be applied through an
20adjustment to the participating utility's return on equity of
21no more than a total of 30 basis points in each of the first 3
22years, of no more than a total of 34 basis points in each of the
233 years thereafter, and of no more than a total of 38 basis
24points in each of the 4 years thereafter, as follows:
25        (1) With respect to each of the incremental annual
26    performance goals established pursuant to paragraph (1) of

 

 

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1    subsection (f) of this Section,
2            (A) for each year that a participating utility
3        other than a combination utility does not achieve the
4        annual goal, the participating utility's return on
5        equity shall be reduced as follows: during years 1
6        through 3, by 5 basis points; during years 4 through 6,
7        by 6 basis points; and during years 7 through 10, by 7
8        basis points; and
9            (B) for each year that a participating utility that
10        is a combination utility does not achieve the annual
11        goal, the participating utility's return on equity
12        shall be reduced as follows: during years 1 through 3,
13        by 10 basis points; during years 4 through 6, by 12
14        basis points; and during years 7 through 10, by 14
15        basis points.
16        (2) With respect to each of the incremental annual
17    performance goals established pursuant to paragraph (2) of
18    subsection (f) of this Section, for each year that the
19    participating utility does not achieve each such goal, the
20    participating utility's return on equity shall be reduced
21    as follows: during years 1 through 3, by 5 basis points;
22    during years 4 through 6, by 6 basis points; and during
23    years 7 through 10, by 7 basis points.
24        (3) With respect to each of the incremental annual
25    performance goals established pursuant to paragraphs (3)
26    and (3.5) of subsection (f) of this Section, for each year

 

 

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1    that a participating utility other than a combination
2    utility does not achieve both such goals, the participating
3    utility's return on equity shall be reduced as follows:
4    during years 1 through 3, by 5 basis points; during years 4
5    through 6, by 6 basis points; and during years 7 through
6    10, by 7 basis points.
7        (4) With respect to each of the incremental annual
8    performance goals established pursuant to paragraph (4) of
9    subsection (f) of this Section, for each year that the
10    participating utility does not achieve each such goal, the
11    participating utility's return on equity shall be reduced
12    as follows: during years 1 through 3, by 5 basis points;
13    during years 4 through 6, by 6 basis points; and during
14    years 7 through 10, by 7 basis points.
15        (5) With respect to each of the incremental annual
16    performance goals established pursuant to subparagraph (5)
17    of subsection (f) of this Section, for each year that the
18    participating utility does not achieve at least 95% of each
19    such goal, the participating utility's return on equity
20    shall be reduced by 5 basis points for each such unachieved
21    goal.
22        (6) With respect to each of the incremental annual
23    performance goals established pursuant to paragraphs (6),
24    (7), and (8) of subsection (f) of this Section, as
25    applicable, which together measure non-operational
26    customer savings and benefits relating to the

 

 

HB2607- 172 -LRB099 06217 AMC 30868 b

1    implementation of the Advanced Metering Infrastructure
2    Deployment Plan, as defined in Section 16-108.6 of this
3    Act, the performance under each such goal shall be
4    calculated in terms of the percentage of the goal achieved.
5    The percentage of goal achieved for each of the goals shall
6    be aggregated, and an average percentage value calculated,
7    for each year of the 10-year period. If the utility does
8    not achieve an average percentage value in a given year of
9    at least 95%, the participating utility's return on equity
10    shall be reduced by 5 basis points.
11    The financial penalties shall be applied as described in
12this subsection (f-5) for the 12-month period in which the
13deficiency occurred through a separate tariff mechanism, which
14shall be filed by the utility together with its metrics. In the
15event the formula rate tariff established pursuant to
16subsection (c) of this Section terminates, the utility's
17obligations under subsection (f) of this Section and this
18subsection (f-5) shall also terminate, provided, however, that
19the tariff mechanism established pursuant to subsection (f) of
20this Section and this subsection (f-5) shall remain in effect
21until any penalties due and owing at the time of such
22termination are applied.
23    The Commission shall, after notice and hearing, enter an
24order within 120 days after the metrics are filed approving, or
25approving with modification, a participating utility's tariff
26or mechanism to satisfy the metrics set forth in subsection (f)

 

 

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1of this Section. On June 1 of each subsequent year, each
2participating utility shall file a report with the Commission
3that includes, among other things, a description of how the
4participating utility performed under each metric and an
5identification of any extraordinary events that adversely
6impacted the utility's performance. Whenever a participating
7utility does not satisfy the metrics required pursuant to
8subsection (f) of this Section, the Commission shall, after
9notice and hearing, enter an order approving financial
10penalties in accordance with this subsection (f-5). The
11Commission-approved financial penalties shall be applied
12beginning with the next rate year. Nothing in this Section
13shall authorize the Commission to reduce or otherwise obviate
14the imposition of financial penalties for failing to achieve
15one or more of the metrics established pursuant to subparagraph
16(1) through (4) of subsection (f) of this Section.
17    (g) On or before July 31, 2014, each participating utility
18shall file a report with the Commission that sets forth the
19average annual increase in the average amount paid per
20kilowatthour for residential eligible retail customers,
21exclusive of the effects of energy efficiency programs,
22comparing the 12-month period ending May 31, 2012; the 12-month
23period ending May 31, 2013; and the 12-month period ending May
2431, 2014. For a participating utility that is a combination
25utility with more than one rate zone, the weighted average
26aggregate increase shall be provided. The report shall be filed

 

 

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1together with a statement from an independent auditor attesting
2to the accuracy of the report. The cost of the independent
3auditor shall be borne by the participating utility and shall
4not be a recoverable expense. "The average amount paid per
5kilowatthour" shall be based on the participating utility's
6tariffed rates actually in effect and shall not be calculated
7using any hypothetical rate or adjustments to actual charges
8(other than as specified for energy efficiency) as an input.
9    In the event that the average annual increase exceeds 2.5%
10as calculated pursuant to this subsection (g), then Sections
1116-108.5, 16-108.6, 16-108.7, and 16-108.8 of this Act, other
12than this subsection, shall be inoperative as they relate to
13the utility and its service area as of the date of the report
14due to be submitted pursuant to this subsection and the utility
15shall no longer be eligible to annually update the
16performance-based formula rate tariff pursuant to subsection
17(d) of this Section. In such event, the then current rates
18shall remain in effect until such time as new rates are set
19pursuant to Article IX of this Act, subject to retroactive
20adjustment, with interest, to reconcile rates charged with
21actual costs, and the participating utility's voluntary
22commitments and obligations under subsection (b) of this
23Section shall immediately terminate, except for the utility's
24obligation to pay an amount already owed to the fund for
25training grants pursuant to a Commission order issued under
26subsection (b) of this Section.

 

 

HB2607- 175 -LRB099 06217 AMC 30868 b

1    In the event that the average annual increase is 2.5% or
2less as calculated pursuant to this subsection (g), then the
3performance-based formula rate shall remain in effect as set
4forth in this Section.
5    For purposes of this Section, the amount per kilowatthour
6means the total amount paid for electric service expressed on a
7per kilowatthour basis, and the total amount paid for electric
8service includes without limitation amounts paid for supply,
9transmission, distribution, surcharges, and add-on taxes
10exclusive of any increases in taxes or new taxes imposed after
11the effective date of this amendatory Act of the 97th General
12Assembly. For purposes of this Section, "eligible retail
13customers" shall have the meaning set forth in Section 16-111.5
14of this Act.
15    The fact that this Section becomes inoperative as set forth
16in this subsection shall not be construed to mean that the
17Commission may reexamine or otherwise reopen prudence or
18reasonableness determinations already made.
19    (h) Sections 16-108.5, 16-108.6, 16-108.7, and 16-108.8 of
20this Act, other than this subsection, are inoperative after
21December 31, 2017 for every participating utility, after which
22time a participating utility shall no longer be eligible to
23annually update the performance-based formula rate tariff
24pursuant to subsection (d) of this Section. At such time, the
25then current rates shall remain in effect until such time as
26new rates are set pursuant to Article IX of this Act, subject

 

 

HB2607- 176 -LRB099 06217 AMC 30868 b

1to retroactive adjustment, with interest, to reconcile rates
2charged with actual costs.
3    By December 31, 2017, the Commission shall prepare and file
4with the General Assembly a report on the infrastructure
5program and the performance-based formula rate. The report
6shall include the change in the average amount per kilowatthour
7paid by residential customers between June 1, 2011 and May 31,
82017. If the change in the total average rate paid exceeds 2.5%
9compounded annually, the Commission shall include in the report
10an analysis that shows the portion of the change due to the
11delivery services component and the portion of the change due
12to the supply component of the rate. The report shall include
13separate sections for each participating utility.
14    In the event Sections 16-108.5, 16-108.6, 16-108.7, and
1516-108.8 of this Act do not become inoperative after December
1631, 2017, then these Sections are inoperative after December
1731, 2022 for every participating utility, after which time a
18participating utility shall no longer be eligible to annually
19update the performance-based formula rate tariff pursuant to
20subsection (d) of this Section. At such time, the then current
21rates shall remain in effect until such time as new rates are
22set pursuant to Article IX of this Act, subject to retroactive
23adjustment, with interest, to reconcile rates charged with
24actual costs.
25    The fact that this Section becomes inoperative as set forth
26in this subsection shall not be construed to mean that the

 

 

HB2607- 177 -LRB099 06217 AMC 30868 b

1Commission may reexamine or otherwise reopen prudence or
2reasonableness determinations already made. The fact that this
3Section becomes inoperative, as set forth in this Section,
4shall not eliminate a utility's obligations under Section 8-103
5of this Act.
6    (i) While a participating utility may use, develop, and
7maintain broadband systems and the delivery of broadband
8services, voice-over-internet-protocol services,
9telecommunications services, and cable and video programming
10services for use in providing delivery services and Smart Grid
11functionality or application to its retail customers,
12including, but not limited to, the installation,
13implementation and maintenance of Smart Grid electric system
14upgrades as defined in Section 16-108.6 of this Act, a
15participating utility is prohibited from offering to its retail
16customers broadband services or the delivery of broadband
17services, voice-over-internet-protocol services,
18telecommunications services, or cable or video programming
19services, unless they are part of a service directly related to
20delivery services or Smart Grid functionality or applications
21as defined in Section 16-108.6 of this Act, and from recovering
22the costs of such offerings from retail customers.
23    (j) Nothing in this Section is intended to legislatively
24overturn the opinion issued in Commonwealth Edison Co. v. Ill.
25Commerce Comm'n, Nos. 2-08-0959, 2-08-1037, 2-08-1137,
261-08-3008, 1-08-3030, 1-08-3054, 1-08-3313 cons. (Ill. App.

 

 

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1Ct. 2d Dist. Sept. 30, 2010). This amendatory Act of the 97th
2General Assembly shall not be construed as creating a contract
3between the General Assembly and the participating utility, and
4shall not establish a property right in the participating
5utility.
6    (k) The changes made in subsections (c) and (d) of this
7Section by this amendatory Act of the 98th General Assembly are
8intended to be a restatement and clarification of existing law,
9and intended to give binding effect to the provisions of House
10Resolution 1157 adopted by the House of Representatives of the
1197th General Assembly and Senate Resolution 821 adopted by the
12Senate of the 97th General Assembly that are reflected in
13paragraph (3) of this subsection. In addition, this amendatory
14Act of the 98th General Assembly preempts and supersedes any
15final Commission orders entered in Docket Nos. 11-0721,
1612-0001, 12-0293, and 12-0321 to the extent inconsistent with
17the amendatory language added to subsections (c) and (d).
18        (1) No earlier than 5 business days after the effective
19    date of this amendatory Act of the 98th General Assembly,
20    each participating utility shall file any tariff changes
21    necessary to implement the amendatory language set forth in
22    subsections (c) and (d) of this Section by this amendatory
23    Act of the 98th General Assembly and a revised revenue
24    requirement under the participating utility's
25    performance-based formula rate. The Commission shall enter
26    a final order approving such tariff changes and revised

 

 

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1    revenue requirement within 21 days after the participating
2    utility's filing.
3        (2) Notwithstanding anything that may be to the
4    contrary, a participating utility may file a tariff to
5    retroactively recover its previously unrecovered actual
6    costs of delivery service that are no longer subject to
7    recovery through a reconciliation adjustment under
8    subsection (d) of this Section. This retroactive recovery
9    shall include any derivative adjustments resulting from
10    the changes to subsections (c) and (d) of this Section by
11    this amendatory Act of the 98th General Assembly. Such
12    tariff shall allow the utility to assess, on current
13    customer bills over a period of 12 monthly billing periods,
14    a charge or credit related to those unrecovered costs with
15    interest at the utility's weighted average cost of capital
16    during the period in which those costs were unrecovered. A
17    participating utility may file a tariff that implements a
18    retroactive charge or credit as described in this paragraph
19    for amounts not otherwise included in the tariff filing
20    provided for in paragraph (1) of this subsection (k). The
21    Commission shall enter a final order approving such tariff
22    within 21 days after the participating utility's filing.
23        (3) The tariff changes described in paragraphs (1) and
24    (2) of this subsection (k) shall relate only to, and be
25    consistent with, the following provisions of this
26    amendatory Act of the 98th General Assembly: paragraph (2)

 

 

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1    of subsection (c) regarding year-end capital structure,
2    subparagraph (D) of paragraph (4) of subsection (c)
3    regarding pension assets, and subsection (d) regarding the
4    reconciliation components related to year-end rate base
5    and interest calculated at a rate equal to the utility's
6    weighted average cost of capital.
7        (4) Nothing in this subsection is intended to effect a
8    dismissal of or otherwise affect an appeal from any final
9    Commission orders entered in Docket Nos. 11-0721, 12-0001,
10    12-0293, and 12-0321 other than to the extent of the
11    amendatory language contained in subsections (c) and (d) of
12    this amendatory Act of the 98th General Assembly.
13    (l) Each participating utility shall be deemed to have been
14in full compliance with all requirements of subsection (b) of
15this Section, subsection (c) of this Section, Section 16-108.6
16of this Act, and all Commission orders entered pursuant to
17Sections 16-108.5 and 16-108.6 of this Act, up to and including
18the effective date of this amendatory Act of the 98th General
19Assembly. The Commission shall not undertake any investigation
20of such compliance and no penalty shall be assessed or adverse
21action taken against a participating utility for noncompliance
22with Commission orders associated with subsection (b) of this
23Section, subsection (c) of this Section, and Section 16-108.6
24of this Act prior to such date. Each participating utility
25other than a combination utility shall be permitted, without
26penalty, a period of 12 months after such effective date to

 

 

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1take actions required to ensure its infrastructure investment
2program is in compliance with subsection (b) of this Section
3and with Section 16-108.6 of this Act. Provided further:
4        (1) if this amendatory Act of the 98th General Assembly
5    takes effect on or before June 15, 2013, the following
6    subparagraphs shall apply to a participating utility other
7    than a combination utility:
8            (A) if the Commission has initiated a proceeding
9        pursuant to subsection (e) of Section 16-108.6 of this
10        Act that is pending as of the effective date of this
11        amendatory Act of the 98th General Assembly, then the
12        order entered in such proceeding shall, after notice
13        and hearing, accelerate the commencement of the meter
14        deployment schedule approved in the final Commission
15        order on rehearing entered in Docket No. 12-0298;
16            (B) if the Commission has entered an order pursuant
17        to subsection (e) of Section 16-108.6 of this Act prior
18        to the effective date of this amendatory Act of the
19        98th General Assembly that does not accelerate the
20        commencement of the meter deployment schedule approved
21        in the final Commission order on rehearing entered in
22        Docket No. 12-0298, then the utility shall file with
23        the Commission, within 45 days after such effective
24        date, a plan for accelerating the commencement of the
25        utility's meter deployment schedule approved in the
26        final Commission order on rehearing entered in Docket

 

 

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1        No. 12-0298; the Commission shall reopen the
2        proceeding in which it entered its order pursuant to
3        subsection (e) of Section 16-108.6 of this Act and
4        shall, after notice and hearing, enter an amendatory
5        order that approves or approves as modified such
6        accelerated plan within 90 days after the utility's
7        filing; or
8            (C) if the Commission has not initiated a
9        proceeding pursuant to subsection (e) of Section
10        16-108.6 of this Act prior to the effective date of
11        this amendatory Act of the 98th General Assembly, then
12        the utility shall file with the Commission, within 45
13        days after such effective date, a plan for accelerating
14        the commencement of the utility's meter deployment
15        schedule approved in the final Commission order on
16        rehearing entered in Docket No. 12-0298 and the
17        Commission shall, after notice and hearing, approve or
18        approve as modified such plan within 90 days after the
19        utility's filing;
20        (2) if this amendatory Act of the 98th General Assembly
21    takes effect after June 15, 2013, then each participating
22    utility other than a combination utility shall file with
23    the Commission, within 45 days after such effective date, a
24    plan for accelerating the commencement of the utility's
25    meter deployment schedule approved in the final Commission
26    order on rehearing entered in Docket No. 12-0298; the

 

 

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1    Commission shall reopen the most recent proceeding in which
2    it entered an order pursuant to subsection (e) of Section
3    16-108.6 of this Act and within 90 days after the utility's
4    filing shall, after notice and hearing, enter an amendatory
5    order that approves or approves as modified such
6    accelerated plan, provided that if there was no such prior
7    proceeding the Commission shall open a new proceeding and
8    within 90 days after the utility's filing shall, after
9    notice and hearing, enter an order that approves or
10    approves as modified such accelerated plan.
11    Any schedule for meter deployment approved by the
12Commission pursuant to subparagraphs (1) or (2) of this
13subsection (l) shall take into consideration procurement times
14for meters and other equipment and operational issues. Nothing
15in this amendatory Act of the 98th General Assembly shall
16shorten or extend the end dates for the 5-year or 10-year
17periods set forth in subsection (b) of this Section or Section
1816-108.6 of this Act. Nothing in this subsection is intended to
19address whether a participating utility has, or has not,
20satisfied any or all of the metrics and performance goals
21established pursuant to subsection (f) of this Section.
22    (m) The provisions of this amendatory Act of the 98th
23General Assembly are severable under Section 1.31 of the
24Statute on Statutes.
25(Source: P.A. 97-616, eff. 10-26-11; 97-646, eff. 12-30-11;
2698-15, eff. 5-22-13.)
 

 

 

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1    (220 ILCS 5/16-108.8)
2    Sec. 16-108.8. Illinois Smart Grid test bed.
3    (a) Within 180 days after the effective date of this
4amendatory Act of the 97th General Assembly, each participating
5utility, as defined by Section 16-108.5 of this Act, shall
6create or otherwise designate a Smart Grid test bed, which may
7be located at one or more places within the utility's system,
8for the purposes of allowing for the testing of Smart Grid
9technologies. The objectives of this test bed shall be to:
10        (1) provide an open, unbiased opportunity for testing
11    programs, technologies, business models, and other Smart
12    Grid-related activities;
13        (2) provide on-grid locations for the testing of
14    potentially innovative Smart Grid-related technologies and
15    services, including but not limited to those funded by the
16    trust or foundation established pursuant to Section
17    16-108.7 of this Act;
18        (3) facilitate testing of business models or services
19    that help integrate Smart Grid-related technologies into
20    the electric grid, especially those business models that
21    may help promote new products and services for retail
22    customers;
23        (4) offer opportunities to test and showcase Smart Grid
24    technologies and services, especially those likely to
25    support the economic development goals of the State of

 

 

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1    Illinois.
2    (b) The test bed shall reside in one or more locations on
3the participating utility's network. Such locations shall be
4chosen by the utility to maximize the opportunity for real-time
5and real-world testing of Smart Grid technologies and services
6taking into account the safety and security of the
7participating utility's grid and grid operations.
8    (c) The participating utility, with input from the Smart
9Grid Advisory Council established pursuant to Section 16-108.6
10of this Act, shall, as part of its filing under subsection (b)
11of Section 16-108.5, include a plan for the creation,
12operation, and administration of the test bed. This plan shall
13address the following:
14        (1) how the utility proposes to comply with each of the
15    objectives set forth in subsection (a) of this Section;
16        (2) the proposed location or locations of the test bed;
17        (3) the process by which the utility will receive,
18    review, and qualify proposals to use the test bed;
19        (4) the criteria by which the utility proposes to
20    qualify proposals to use the test bed, including, but not
21    limited to, safety, reliability, security, customer data
22    security, privacy, and economic development
23    considerations;
24        (5) the engineering and operations support that the
25    utility will provide to test bed users, including provision
26    of customer data; and

 

 

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1        (6) the estimated costs to establish, administer and
2    promote the availability of the test bed.
3    (d) The test bed should be open to all qualified entities
4wishing to test programs, technologies, business models, and
5other Smart Grid-related activities, provided that the utility
6retains control of its grid and operations and may reject any
7programs, technologies, business models, and other Smart
8Grid-related activities that threaten the reliability, safety,
9security, or operations of its network, or that would threaten
10the security of customer-identifiable data in the judgment of
11the utility. The number of technologies and entities
12participating in the test bed at any time may be limited by the
13utility based on its determination of its ability to maintain a
14secure, safe, and reliable grid.
15    (e) At a minimum, the test bed shall have the ability to
16receive live signals from PJM Interconnection LLC or other
17applicable regional transmission organization, the ability to
18test new applications in a utility scale environment (to
19include ramp rate regulations for distributed wind and solar
20resources), critical peak price response, and market-based
21power dispatch.
22    (f) At the end of the fourth year of operation the test bed
23shall be subject to an independent evaluation to determine if
24the test bed is meeting the objectives of this Section or is
25likely to meet the objectives in the future. The evaluation
26shall include the performance of the utility as test bed

 

 

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1operator. Subject to the findings, the utility and the trust or
2foundation established pursuant to Section 16-108.7 of this Act
3may choose to continue operating the test bed.
4    (g) The utility shall be entitled to recover all prudently
5incurred and reasonable costs associated with evaluation of
6proposals, engineering, construction, operation, and
7administration of the test bed through the performance-based
8formula rate tariff established pursuant to Section 16-108.5 of
9this Act.
10    (h) The utility is authorized to charge fees to users of
11the test bed that shall recover the costs associated with the
12incremental direct costs to the utility associated with
13administration of the test bed, provided, however, that any
14such fees collected by the utility shall be used to offset the
15costs to be recovered pursuant to subsection (g) of this
16Section.
17    (i) On a quarterly basis, the utility shall provide the
18trust or foundation established pursuant to Section 16-108.7 of
19this Act with a report summarizing test bed activities,
20customers, discoveries, and other information as shall be
21mutually deemed relevant.
22    (j) To the extent practicable, the utility and trust or
23foundation established pursuant to Section 16-108.7 of this Act
24shall jointly pursue resources that enhance the capabilities
25and capacity of the test bed.
26    (k) If Section 16-108.5 of this Act becomes inoperative

 

 

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1with respect to one or more participating utilities as set
2forth in subsection (g) or (h) of that Section, then Sections
316-108.5, 16-108.6, 16-108.7, and 16-108.8 of this Act shall
4become inoperative as to each affected utility and its service
5area on the same date as Section 16-108.5 become inoperative.
6(Source: P.A. 97-616, eff. 10-26-11.)
 
7    (220 ILCS 5/16-111.5)
8    Sec. 16-111.5. Provisions relating to electricity
9procurement.
10    (a) An electric utility that on December 31, 2005 served at
11least 100,000 customers in Illinois shall procure power and
12energy for its eligible retail customers in accordance with the
13applicable provisions set forth in Section 1-75 of the Illinois
14Power Agency Act and this Section. A small multi-jurisdictional
15electric utility that on December 31, 2005 served less than
16100,000 customers in Illinois may elect to procure power and
17energy for all or a portion of its eligible Illinois retail
18customers in accordance with the applicable provisions set
19forth in this Section and Section 1-75 of the Illinois Power
20Agency Act. This Section shall not apply to a small
21multi-jurisdictional utility until such time as a small
22multi-jurisdictional utility requests the Illinois Power
23Agency to prepare an electricity a procurement plan for its
24eligible retail customers. "Eligible retail customers" for the
25purposes of this Section means those retail customers that

 

 

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1purchase power and energy from the electric utility under
2fixed-price bundled service tariffs, other than those retail
3customers whose service is declared or deemed competitive under
4Section 16-113 and those other customer groups specified in
5this Section, including self-generating customers, customers
6electing hourly pricing, or those customers who are otherwise
7ineligible for fixed-price bundled tariff service. Those
8customers that are excluded from the definition of "eligible
9retail customers" shall not be included in the electricity
10procurement plan load requirements, and the utility shall
11procure any supply requirements, including capacity, ancillary
12services, and hourly priced energy, in the applicable markets
13as needed to serve those customers, provided that the utility
14may include in its electricity procurement plan load
15requirements for the load that is associated with those retail
16customers whose service has been declared or deemed competitive
17pursuant to Section 16-113 of this Act to the extent that those
18customers are purchasing power and energy during one of the
19transition periods identified in subsection (b) of Section
2016-113 of this Act.
21    (b) An electricity A procurement plan shall be prepared for
22each electric utility consistent with the applicable
23requirements of the Illinois Power Agency Act and this Section.
24For purposes of this Section, Illinois electric utilities that
25are affiliated by virtue of a common parent company are
26considered to be a single electric utility. Small

 

 

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

 

 

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

 

 

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

 

 

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

 

 

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1        (4) Proposed procedures for balancing loads. The
2    electricity procurement plan shall include, for load
3    requirements included in the electricity procurement plan,
4    the process for (i) hourly balancing of supply and demand
5    and (ii) the criteria for portfolio re-balancing in the
6    event of significant shifts in load.
7    (c) The procurement process set forth in Section 1-75 of
8the Illinois Power Agency Act and subsection (e) of this
9Section shall be administered by a procurement administrator
10and monitored by a procurement monitor.
11        (1) The procurement administrator shall:
12            (i) design the final procurement process in
13        accordance with Section 1-75 of the Illinois Power
14        Agency Act and subsection (e) of this Section following
15        Commission approval of the electricity procurement
16        plan;
17            (ii) develop benchmarks in accordance with
18        subsection (e)(3) to be used to evaluate bids; these
19        benchmarks shall be submitted to the Commission for
20        review and approval on a confidential basis prior to
21        the procurement event;
22            (iii) serve as the interface between the electric
23        utility and suppliers;
24            (iv) manage the bidder pre-qualification and
25        registration process;
26            (v) obtain the electric utilities' agreement to

 

 

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

 

 

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

 

 

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

 

 

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1    the Agency on the electricity procurement plan. Other
2    interested entities also may comment on the electricity
3    procurement plan. All comments submitted to the Agency
4    shall be specific, supported by data or other detailed
5    analyses, and, if objecting to all or a portion of the
6    electricity procurement plan, accompanied by specific
7    alternative wording or proposals. All comments shall be
8    posted on the Agency's and Commission's websites. During
9    this 30-day comment period, the Agency shall hold at least
10    one public hearing within each utility's service area for
11    the purpose of receiving public comment on the electricity
12    procurement plan. Within 14 days following the end of the
13    30-day review period, the Agency shall revise the
14    electricity procurement plan as necessary based on the
15    comments received and file the electricity procurement
16    plan with the Commission and post the electricity
17    procurement plan on the websites.
18        (3) Within 5 days after the filing of the electricity
19    procurement plan, any person objecting to the electricity
20    procurement plan shall file an objection with the
21    Commission. Within 10 days after the filing, the Commission
22    shall determine whether a hearing is necessary. The
23    Commission shall enter its order confirming or modifying
24    the electricity procurement plan within 90 days after the
25    filing of the electricity procurement plan by the Illinois
26    Power Agency.

 

 

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

 

 

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

 

 

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

 

 

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

 

 

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

 

 

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1        including ancillary services, capacity, and day-ahead
2        or real time energy or both; provided, however, that if
3