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 Illinois Compiled Statutes (Last Updated: March 28, 2015)
  REGULATION
 CHAPTER 220. UTILITIES
  220 ILCS 5. Public Utilities Act.
 Article XVI. Electric Service Customer Choice And Rate Relief Law Of 1997

  Article XVI. Electric Service Customer Choice And Rate Relief Law Of 1997  


 
    (220 ILCS 5/Art. XVI heading)
ARTICLE XVI. ELECTRIC SERVICE CUSTOMER CHOICE AND RATE
RELIEF LAW OF 1997

    (220 ILCS 5/16-101)
    Sec. 16-101. Short title and applicability.
    (a) This Article may be cited as the Electric Service Customer Choice and Rate Relief Law of 1997 and shall apply to electric utilities and alternative retail electric suppliers as defined in this Article. Except to the extent modified or supplemented by the provisions of this Article, or where the context clearly renders such provisions inapplicable, the other Articles of the Public Utilities Act pertaining to public utilities, public utility rates and services and the regulation thereof, are fully and equally applicable to the tariffed services electric utilities provide.
    (b) The provisions of subsections (a) through (h) of Section 16-111 of this Act shall not be applicable to any electric utility which elects to file biennial rate proceedings before the Commission in the years 1998, 2000 and 2002. An electric utility electing this option shall do so by filing a notice of such election with the Commission within 60 days after the effective date of this amendatory Act of 1997, or its right to make such election shall be irrevocably waived. An electric utility electing the option specified in this paragraph shall file its rate proceeding with the Commission no later than August 1 of the years 1998, 2000, and 2002. The electric utility's filing shall comply with all requirements of 83 Illinois Administrative Code Parts 255 and 285 as though the electric utility were filing for an increase in its rates, without regard to whether such filing would produce an increase, a decrease or no change in the electric utility's rates and the Commission shall review the electric utility's filing and shall issue its order in accordance with the provisions of Section 9-201 of this Act.
(Source: P.A. 90-561, eff. 12-16-97.)

    (220 ILCS 5/16-101A)
    Sec. 16-101A. Legislative findings.
    (a) The citizens and businesses of the State of Illinois have been well-served by a comprehensive electrical utility system which has provided safe, reliable, and affordable service. The electrical utility system in the State of Illinois has historically been subject to State and federal regulation, aimed at assuring the citizens and businesses of the State of safe, reliable, and affordable service, while at the same time assuring the utility system of a return on its investment.
    (b) Competitive forces are affecting the market for electricity as a result of recent federal regulatory and statutory changes and the activities of other states. Competition in the electric services market may create opportunities for new products and services for customers and lower costs for users of electricity. Long-standing regulatory relationships need to be altered to accommodate the competition that could fundamentally alter the structure of the electric services market.
    (c) With the advent of increasing competition in this industry, the State has a continued interest in assuring that the safety, reliability, and affordability of electrical power is not sacrificed to competitive pressures, and to that end, intends to implement safeguards to assure that the industry continues to operate the electrical system in a manner that will serve the public's interest. Under the existing regulatory framework, the industry has been encouraged to undertake certain investments in its physical plant and personnel to enhance its efficient operation, the cost of which it has been permitted to pass on to consumers. The State has an interest in providing the existing utilities a reasonable opportunity to obtain a return on certain investments on which they depended in undertaking those commitments in the first instance while, at the same time, not permitting new entrants into the industry to take unreasonable advantage of the investments made by the formerly regulated industry.
    (d) A competitive wholesale and retail market must benefit all Illinois citizens. The Illinois Commerce Commission should act to promote the development of an effectively competitive electricity market that operates efficiently and is equitable to all consumers. Consumer protections must be in place to ensure that all customers continue to receive safe, reliable, affordable, and environmentally safe electric service.
    (e) All consumers must benefit in an equitable and timely fashion from the lower costs for electricity that result from retail and wholesale competition and receive sufficient information to make informed choices among suppliers and services. The use of renewable resources and energy efficiency resources should be encouraged in competitive markets.
    (f) The efficiency of electric markets depends both upon the competitiveness of supply and upon the price-responsiveness of the demand for service. Therefore, to ensure the lowest total cost of service and to enhance the reliability of service, all classes of the electricity customers of electric utilities should have access to and be able to voluntarily use real-time pricing and other price-response and demand-response mechanisms.
    (g) Including cost-effective renewable resources and demand-response resources in a diverse electricity supply portfolio will reduce long-term direct and indirect costs to consumers by decreasing environmental impacts and by avoiding or delaying the need for new generation, transmission, and distribution infrastructure. It serves the public interest to allow electric utilities to recover costs for reasonably and prudently incurred expenses for electricity generated by renewable resources and demand-response resources.
    (h) Including electricity generated by clean coal facilities, as defined under Section 1-10 of the Illinois Power Agency Act, in a diverse electricity procurement portfolio will reduce the need to purchase, directly or indirectly, carbon dioxide emission credits and will decrease environmental impacts. It serves the public interest to allow electric utilities to recover costs for reasonably and prudently incurred expenses for sourcing electricity generated by clean coal facilities.
(Source: P.A. 94-977, eff. 6-30-06; 95-481, eff. 8-28-07; 95-1027, eff. 6-1-09.)

    (220 ILCS 5/16-102)
    Sec. 16-102. Definitions. For the purposes of this Article the following terms shall be defined as set forth in this Section.
    "Alternative retail electric supplier" means every person, cooperative, corporation, municipal corporation, company, association, joint stock company or association, firm, partnership, individual, or other entity, their lessees, trustees, or receivers appointed by any court whatsoever, that offers electric power or energy for sale, lease or in exchange for other value received to one or more retail customers, or that engages in the delivery or furnishing of electric power or energy to such retail customers, and shall include, without limitation, resellers, aggregators and power marketers, but shall not include (i) electric utilities (or any agent of the electric utility to the extent the electric utility provides tariffed services to retail customers through that agent), (ii) any electric cooperative or municipal system as defined in Section 17-100 to the extent that the electric cooperative or municipal system is serving retail customers within any area in which it is or would be entitled to provide service under the law in effect immediately prior to the effective date of this amendatory Act of 1997, (iii) a public utility that is owned and operated by any public institution of higher education of this State, or a public utility that is owned by such public institution of higher education and operated by any of its lessees or operating agents, within any area in which it is or would be entitled to provide service under the law in effect immediately prior to the effective date of this amendatory Act of 1997, (iv) a retail customer to the extent that customer obtains its electric power and energy from that customer's own cogeneration or self-generation facilities, (v) an entity that owns, operates, sells, or arranges for the installation of a customer's own cogeneration or self-generation facilities, but only to the extent the entity is engaged in owning, selling or arranging for the installation of such facility, or operating the facility on behalf of such customer, provided however that any such third party owner or operator of a facility built after January 1, 1999, complies with the labor provisions of Section 16-128(a) as though such third party were an alternative retail electric supplier, or (vi) an industrial or manufacturing customer that owns its own distribution facilities, to the extent that the customer provides service from that distribution system to a third-party contractor located on the customer's premises that is integrally and predominantly engaged in the customer's industrial or manufacturing process; provided, that if the industrial or manufacturing customer has elected delivery services, the customer shall pay transition charges applicable to the electric power and energy consumed by the third-party contractor unless such charges are otherwise paid by the third party contractor, which shall be calculated based on the usage of, and the base rates or the contract rates applicable to, the third-party contractor in accordance with Section 16-102.
    An entity that furnishes the service of charging electric vehicles does not and shall not be deemed to sell electricity and is not and shall not be deemed an alternative retail electric supplier, and is not subject to regulation as such under this Act notwithstanding the basis on which the service is provided or billed. If, however, the entity is otherwise deemed an alternative retail electric supplier under this Act, or is otherwise subject to regulation under this Act, then that entity is not exempt from and remains subject to the otherwise applicable provisions of this Act. The installation, maintenance, and repair of an electric vehicle charging station shall comply with the requirements of subsection (a) of Section 16-128 and Section 16-128A of this Act.
    For purposes of this Section, the term "electric vehicles" has the meaning ascribed to that term in Section 10 of the Electric Vehicle Act.
    "Base rates" means the rates for those tariffed services that the electric utility is required to offer pursuant to subsection (a) of Section 16-103 and that were identified in a rate order for collection of the electric utility's base rate revenue requirement, excluding (i) separate automatic rate adjustment riders then in effect, (ii) special or negotiated contract rates, (iii) delivery services tariffs filed pursuant to Section 16-108, (iv) real-time pricing, or (v) tariffs that were in effect prior to October 1, 1996 and that based charges for services on an index or average of other utilities' charges, but including (vi) any subsequent redesign of such rates for tariffed services that is authorized by the Commission after notice and hearing.
    "Competitive service" includes (i) any service that has been declared to be competitive pursuant to Section 16-113 of this Act, (ii) contract service, and (iii) services, other than tariffed services, that are related to, but not necessary for, the provision of electric power and energy or delivery services.
    "Contract service" means (1) services, including the provision of electric power and energy or other services, that are provided by mutual agreement between an electric utility and a retail customer that is located in the electric utility's service area, provided that, delivery services shall not be a contract service until such services are declared competitive pursuant to Section 16-113; and also means (2) the provision of electric power and energy by an electric utility to retail customers outside the electric utility's service area pursuant to Section 16-116. Provided, however, contract service does not include electric utility services provided pursuant to (i) contracts that retail customers are required to execute as a condition of receiving tariffed services, or (ii) special or negotiated rate contracts for electric utility services that were entered into between an electric utility and a retail customer prior to the effective date of this amendatory Act of 1997 and filed with the Commission.
    "Delivery services" means those services provided by the electric utility that are necessary in order for the transmission and distribution systems to function so that retail customers located in the electric utility's service area can receive electric power and energy from suppliers other than the electric utility, and shall include, without limitation, standard metering and billing services.
    "Electric utility" means a public utility, as defined in Section 3-105 of this Act, that has a franchise, license, permit or right to furnish or sell electricity to retail customers within a service area.
    "Mandatory transition period" means the period from the effective date of this amendatory Act of 1997 through January 1, 2007.
    "Municipal system" shall have the meaning set forth in Section 17-100.
    "Real-time pricing" means tariffed retail charges for delivered electric power and energy that vary hour-to-hour and are determined from wholesale market prices using a methodology approved by the Illinois Commerce Commission.
    "Retail customer" means a single entity using electric power or energy at a single premises and that (A) either (i) is receiving or is eligible to receive tariffed services from an electric utility, or (ii) that is served by a municipal system or electric cooperative within any area in which the municipal system or electric cooperative is or would be entitled to provide service under the law in effect immediately prior to the effective date of this amendatory Act of 1997, or (B) an entity which on the effective date of this Act was receiving electric service from a public utility and (i) was engaged in the practice of resale and redistribution of such electricity within a building prior to January 2, 1957, or (ii) was providing lighting services to tenants in a multi-occupancy building, but only to the extent such resale, redistribution or lighting service is authorized by the electric utility's tariffs that were on file with the Commission on the effective date of this Act.
    "Service area" means (i) the geographic area within which an electric utility was lawfully entitled to provide electric power and energy to retail customers as of the effective date of this amendatory Act of 1997, and includes (ii) the location of any retail customer to which the electric utility was lawfully providing electric utility services on such effective date.
    "Small commercial retail customer" means those nonresidential retail customers of an electric utility consuming 15,000 kilowatt-hours or less of electricity annually in its service area.
    "Tariffed service" means services provided to retail customers by an electric utility as defined by its rates on file with the Commission pursuant to the provisions of Article IX of this Act, but shall not include competitive services.
    "Transition charge" means a charge expressed in cents per kilowatt-hour that is calculated for a customer or class of customers as follows for each year in which an electric utility is entitled to recover transition charges as provided in Section 16-108:
        (1) the amount of revenue that an electric utility

    
would receive from the retail customer or customers if it were serving such customers' electric power and energy requirements as a tariffed service based on (A) all of the customers' actual usage during the 3 years ending 90 days prior to the date on which such customers were first eligible for delivery services pursuant to Section 16-104, and (B) on (i) the base rates in effect on October 1, 1996 (adjusted for the reductions required by subsection (b) of Section 16-111, for any reduction resulting from a rate decrease under Section 16-101(b), for any restatement of base rates made in conjunction with an elimination of the fuel adjustment clause pursuant to subsection (b), (d), or (f) of Section 9-220 and for any removal of decommissioning costs from base rates pursuant to Section 16-114) and any separate automatic rate adjustment riders (other than a decommissioning rate as defined in Section 16-114) under which the customers were receiving or, had they been customers, would have received electric power and energy from the electric utility during the year immediately preceding the date on which such customers were first eligible for delivery service pursuant to Section 16-104, or (ii) to the extent applicable, any contract rates, including contracts or rates for consolidated or aggregated billing, under which such customers were receiving electric power and energy from the electric utility during such year;
        (2) less the amount of revenue, other than revenue
    
from transition charges and decommissioning rates, that the electric utility would receive from such retail customers for delivery services provided by the electric utility, assuming such customers were taking delivery services for all of their usage, based on the delivery services tariffs in effect during the year for which the transition charge is being calculated and on the usage identified in paragraph (1);
        (3) less the market value for the electric power and
    
energy that the electric utility would have used to supply all of such customers' electric power and energy requirements, as a tariffed service, based on the usage identified in paragraph (1), with such market value determined in accordance with Section 16-112 of this Act;
        (4) less the following amount which represents the
    
amount to be attributed to new revenue sources and cost reductions by the electric utility through the end of the period for which transition costs are recovered pursuant to Section 16-108, referred to in this Article XVI as a "mitigation factor":
            (A) for nonresidential retail customers, an
        
amount equal to the greater of (i) 0.5 cents per kilowatt-hour during the period October 1, 1999 through December 31, 2004, 0.6 cents per kilowatt-hour in calendar year 2005, and 0.9 cents per kilowatt-hour in calendar year 2006, multiplied in each year by the usage identified in paragraph (1), or (ii) an amount equal to the following percentages of the amount produced by applying the applicable base rates (adjusted as described in subparagraph (1)(B)) or contract rate to the usage identified in paragraph (1): 8% for the period October 1, 1999 through December 31, 2002, 10% in calendar years 2003 and 2004, 11% in calendar year 2005 and 12% in calendar year 2006; and
            (B) for residential retail customers, an amount
        
equal to the following percentages of the amount produced by applying the base rates in effect on October 1, 1996 (adjusted as described in subparagraph (1)(B)) to the usage identified in paragraph (1): (i) 6% from May 1, 2002 through December 31, 2002, (ii) 7% in calendar years 2003 and 2004, (iii) 8% in calendar year 2005, and (iv) 10% in calendar year 2006;
        (5) divided by the usage of such customers identified
    
in paragraph (1),
provided that the transition charge shall never be less than zero.
    "Unbundled service" means a component or constituent part of a tariffed service which the electric utility subsequently offers separately to its customers.
(Source: P.A. 97-1128, eff. 8-28-12.)

    (220 ILCS 5/16-103)
    Sec. 16-103. Service obligations of electric utilities.
    (a) An electric utility shall continue offering to retail customers each tariffed service that it offered as a distinct and identifiable service on the effective date of this amendatory Act of 1997 until the service is (i) declared competitive pursuant to Section 16-113, or (ii) abandoned pursuant to Section 8-508. Nothing in this subsection shall be construed as limiting an electric utility's right to propose, or the Commission's power to approve, allow or order modifications in the rates, terms and conditions for such services pursuant to Article IX or Section 16-111 of this Act.
    (b) An electric utility shall also offer, as tariffed services, delivery services in accordance with this Article, the power purchase options described in Section 16-110 and real-time pricing as provided in Section 16-107.
    (c) Notwithstanding any other provision of this Article, each electric utility shall continue offering to all residential customers and to all small commercial retail customers in its service area, as a tariffed service, bundled electric power and energy delivered to the customer's premises consistent with the bundled utility service provided by the electric utility on the effective date of this amendatory Act of 1997. Upon declaration of the provision of electric power and energy as competitive, the electric utility shall continue to offer to such customers, as a tariffed service, bundled service options at rates which reflect recovery of all cost components for providing the service. For those components of the service which have been declared competitive, cost shall be the market based prices. Market based prices as referred to herein shall mean, for electric power and energy, either (i) those prices for electric power and energy determined as provided in Section 16-112, or (ii) the electric utility's cost of obtaining the electric power and energy at wholesale through a competitive bidding or other arms-length acquisition process.
    (d) Any residential or small commercial retail customer which elects delivery services is entitled to return to the electric utility's bundled utility tariffed service offering provided in accordance with subsection (c) of this Section upon payment of a reasonable administrative fee which shall be set forth in the tariff. If the residential or small commercial customer has not elected delivery services within 2 billing cycles after returning to the electric utility's bundled utility tariffed service offering, then the electric utility shall be entitled to impose the condition that such customer may not elect delivery services for up to 12 months after the date on which the customer returned to bundled utility tariffed service, provided, however, that the customer shall not be permitted to return to the same alternative retail electric supplier within 2 billing cycles after the customer returned to bundled utility tariffed service other than in situations where the return was in error, inadvertent, or the result of any other unintended operational consequence.
    (e) The Commission shall not require an electric utility to offer any tariffed service other than the services required by this Section, and shall not require an electric utility to offer any competitive service.
(Source: P.A. 97-497, eff. 8-22-11.)

    (220 ILCS 5/16-103.1)
    Sec. 16-103.1. Tariffed service to Unit Owners' Associations. An electric utility that serves at least 2,000,000 customers must provide tariffed service to Unit Owners' Associations, as defined by Section 2 of the Condominium Property Act, for condominium properties that are not restricted to nonresidential use at rates that do not exceed on average the rates offered to residential customers on an annual basis. Within 10 days after the effective date of this amendatory Act, the electric utility shall provide the tariffed service to Unit Owners' Associations required by this Section and shall reinstate any residential all-electric discount applicable to any Unit Owners' Association that received such a discount on December 31, 2006. For purposes of this Section, "residential customers" means those retail customers of an electric utility that receive (i) electric utility service for household purposes distributed to a dwelling of 2 or fewer units that is billed under a residential rate or (ii) electric utility service for household purposes distributed to a dwelling unit or units that is billed under a residential rate and is registered by a separate meter for each dwelling unit.
(Source: P.A. 95-481, eff. 8-28-07.)

    (220 ILCS 5/16-103.2)
    Sec. 16-103.2. Market Settlement Service.
    (a) Notwithstanding anything to the contrary, an electric utility shall be permitted, at its election, to provide Market Settlement Service, which, for purposes of this Section, shall mean a tariffed, unbundled electric power and energy supply service applicable to all of the electric utility's retail customers having maximum demands exceeding 400 kilowatts, as measured in accordance with the electric utility's retail tariffs, that do not otherwise purchase all of their electric power and energy supply service from the electric utility. Market Settlement Service shall apply to the difference between (i) the actual quantities of electric power and energy supply provided to any such retail customer during a given period and (ii) the quantities of such supply that were deemed to have been provided to such retail customer for the purposes of the applicable regional transmission organization's final wholesale market settlements during that same period. An electric utility providing Market Settlement Service may also, at its election, include in Market Settlement Service electric capacity, transmission services, or other services that are also provided by or through a regional transmission organization to retail customers who receive tariffed electric power and energy supply service with hourly pricing provisions at quantities assigned to such retail customer pursuant to the electric utility's Market Settlement Service tariff. Charges (if the actual quantities provided were greater) or credits (if the actual quantities provided were less) shall be calculated based on the same unit rate or rates set forth in the electric utility's tariff or tariffs for electric power and energy supply service with hourly pricing provisions applicable to its retail customers having maximum demands exceeding 400 kilowatts, provided, however, that any reconciliation provision set forth in such tariff or tariffs, including any charges or credits resulting therefrom, shall not apply to Market Settlement Service.
    An electric utility providing Market Settlement Service shall be permitted to recover all of its reasonable and prudently incurred administrative and operational costs of providing this service from all of its retail customers through its delivery services charges. An electric utility providing Market Settlement Service shall be permitted to recover its reasonable and prudent initial implementation and start-up costs from retail consumers having maximum demands exceeding 400 kilowatts through its delivery service charges.
    (b) Market Settlement Service shall be provided pursuant to a tariff of the electric utility on file with the Commission. The electric utility's Market Settlement Service tariff shall include provisions for the determination of the quantities subject to Market Settlement Service for any retail customer that receives only a portion of its electric power and energy requirements from an alternative retail electric supplier or electric utility operating outside of its service territory. Notwithstanding subsection (a) of this Section, the electric utility may elect to (i) exclude from Market Settlement Service any portion of the difference described in subsection (a) of this Section attributable to a delayed initial retail electric service bill for a given period and (ii) provide Market Settlement Service limited to an entire retail billing period or periods, without proration, notwithstanding that the applicable regional transmission organization's final wholesale market settlements may have occurred on a date within a retail billing period.
    (c) An electric utility that has a tariff in effect pursuant to this Section shall not be subject to, or allowed to pursue, any other claims, adjustments, settlements, or offsets related to the cost of any difference in the actual quantities of electric energy, capacity, transmission services, or other services included in Market Settlement Service, provided, however, that the provisions of this subsection (c) shall not, consistent with the provisions of this Act, (i) preclude any subsequent and separate adjustments made to the same retail customer's electric service account pursuant to a tariff authorized by this Section because of other differences, whether for the same or a different meter or for the same or different period or (ii) reduce or impair in any way an electric utility's authority to charge a retail customer for unmetered electric service related to the retail customer's unlawful tampering with or interference with electric service, including, but not limited to, any other charges allowed by law or the electric utility's tariffs.
    (d) A tariff authorized by this Section may be established outside of either (i) a filing seeking a general change in rates under Article IX of this Act or (ii) a filing authorized under Section 16-108.5 of this Act. The Commission shall review and, by order, approve, or approve as modified, the proposed tariff within 180 days after the date on which it is filed. In the event the Commission approves such a tariff with modifications, the electric utility shall not be obligated to place the modified tariff into effect. In such event, the electric utility must, within 14 days after any Commission order, withdraw its proposed tariff and its election to provide Market Settlement Service. If a Market Settlement Service tariff does become effective, such tariff shall remain in effect thereafter at the discretion of the electric utility.
    (e) Notwithstanding anything in this Act to the contrary, an electric utility providing Market Settlement Service shall not be liable to any retail customer, alternative retail electric supplier, or electric utility operating outside of its service territory for any adjustment in the quantity of any transmission or retail electric supply service for which the applicable regional transmission organization under its tariffs, agreements, and market and business rules will no longer make a corresponding adjustment to the wholesale market settlements.
(Source: P.A. 98-554, eff. 1-1-14.)

    (220 ILCS 5/16-104)
    Sec. 16-104. Delivery services transition plan. An electric utility shall provide delivery services to retail customers in accordance with the provisions of this Section.
    (a) Each electric utility shall offer delivery services to retail customers located in its service area in accordance with the following provisions:
        (1) On or before October 1, 1999, the electric

    
utility shall offer delivery services (i) to any non-residential retail customer whose average monthly maximum electrical demand on the electric utility's system during the 6 months with the customer's highest monthly maximum demands in the 12 months ending June 30, 1999 equals or exceeds 4 megawatts; (ii) to any non-governmental, non-residential, commercial retail customers under common ownership doing business at 10 or more separate locations within the electric utility's service area, if the aggregate coincident average monthly maximum electrical demand of all such locations during the 6 months with the customer's highest monthly maximum electrical demands during the 12 months ending June 30, 1999 equals or exceeds 9.5 megawatts, provided, however, that an electric utility's obligation to offer delivery services under this clause (ii) shall not exceed 3.5% of the maximum electric demand on the electric utility's system in the 12 months ending June 30, 1999; and (iii) to non-residential retail customers whose annual electric energy use comprises 33% of the kilowatt-hour sales, excluding the kilowatt-hour sales to customers described in clauses (i) and (ii), to each non-residential retail customer class of the electric utility.
        (2) On or before October 1, 2000, the electric
    
utility shall offer delivery services to the eligible governmental customers described in subsections (a) and (b) of Section 16-125A if the aggregate coincident average monthly maximum electrical demand of such customers during the 6 months with the customers' highest monthly maximum electrical demands during the 12 months ending June 30, 2000 equals or exceeds 9.5 megawatts.
        (2.5) On or before June 1, 2000, an electric utility
    
serving more than 1,000,000 customers in this State shall offer delivery services to retail customers whose annual electric energy use comprises 33% of the kilowatt hour sales to that group of retail customers that are classified under Division D, Groups 20 through 39 of the Standard Industrial Classifications set forth in the Standard Industrial Classification Manual published by the United States Office of Management and Budget, excluding the kilowatt-hour sales to those customers that are eligible for delivery services pursuant to clause (1)(i), and shall offer delivery services to its remaining retail customers classified under Division D, Groups 20 through 39 on or before October 1, 2000.
        (3) On or before December 31, 2000, the electric
    
utility shall offer delivery services to all remaining nonresidential retail customers in its service area.
        (4) On or before May 1, 2002, the electric utility
    
shall offer delivery services to all residential retail customers in its service area.
    The loads and kilowatt-hour sales used for purposes of this subsection shall be those for the 12 months ending June 30, 1999 for nonresidential retail customers. The electric utility shall identify those customers to be offered delivery service pursuant to clause (1)(iii) and paragraph (2.5) of subsection (a) of this Section and Section 16-111(e)(B)(iii) pursuant to a lottery or other random nondiscriminatory selection process set forth in the electric utility's delivery services implementation plan pursuant to Section 16-105, which process may include a registration process giving each nonresidential customer the opportunity to register for eligibility for delivery services under this Section, with a lottery of registered customers to be conducted if the annual electric energy use of all registered customers exceeds the limit set forth in clause (1)(iii) or clause (2.5) or Section 16-111(e)(B)(iii), as applicable; provided that the provision of this amendatory Act of 1999 as it relates to the registration and lottery process under clause (1)(iii) is not intended to nor does it make any change in the meaning of this Section, but is intended to remove possible ambiguities, thereby confirming the existing meaning of this Section prior to the effective date of this amendatory Act of 1999. Provided, that non-residential retail customers under common ownership at separate locations within the electric utility's service area may elect, prior to the date the electric utility conducts the lottery or other random selection process for purposes of clause (1)(iii), to designate themselves as a common ownership group, to be excluded from such lottery and to instead participate in a separate lottery for such common ownership group pursuant to which delivery services will be offered to non-residential retail customers comprising 33% of the total kilowatt-hour sales to the common ownership group on or before October 1, 1999. For purposes of this subsection (a), an electric utility may define "common ownership" to exclude sites which are not part of the same business, provided, that auxiliary establishments as defined in the Standard Industrial Classification Manual published by the United States Office of Management and Budget shall not be excluded.
    (b) The electric utility shall allow the aggregation of loads that are eligible for delivery services so long as such aggregation meets the criteria for delivery of electric power and energy applicable to the electric utility established by the regional reliability council to which the electric utility belongs, by an independent system operating organization to which the electric utility belongs, or by another organization responsible for overseeing the integrity and reliability of the transmission system, as such criteria are in effect from time to time. The Commission may adopt rules and regulations governing the criteria for aggregation of the loads utilizing delivery services, but its failure to do so shall not preclude any eligible customer from electing delivery services. The electric utility shall allow such aggregation for any voluntary grouping of customers, including without limitation those having a common agent with contractual authority to purchase electric power and energy and delivery services on behalf of all customers in the grouping.
    (c) An electric utility shall allow a retail customer that generates power for its own use to include the electrical demand obtained from the customer's cogeneration or self-generation facilities that is coincident with the retail customer's maximum monthly electrical demand on the electric utility's system in any determination of the customer's maximum monthly electrical demand for purposes of determining when such retail customer shall be offered delivery services pursuant to clause (i) of subparagraph (1) of subsection (a) of this Section.
    (d) The Commission shall establish charges, terms and conditions for delivery services in accordance with Section 16-108.
    (e) Subject to the terms and conditions which the electric utility is entitled to impose in accordance with Section 16-108, a retail customer that is eligible to elect delivery services pursuant to subsection (a) may place all or a portion of its electric power and energy requirements on delivery services.
    (f) An electric utility may require a retail customer who elects to (i) use an alternative retail electric supplier or another electric utility for some but not all of its electric power or energy requirements, and (ii) use the electric utility for any portion of its remaining electric power and energy requirements, to place the portion of the customer's electric power or energy requirement that is to be served by the electric utility on a tariff containing charges that are set to recover the lowest reasonably available cost to the electric utility of acquiring electric power and energy on the wholesale electric market to serve such remaining portion of the customer's electric power and energy requirement, reasonable compensation for arranging for and providing such electric power or energy, and the electric utility's other costs of providing service to such remaining electric power and energy requirement.
(Source: P.A. 90-561, eff. 12-16-97; 91-50, eff. 6-30-99.)

    (220 ILCS 5/16-105)
    Sec. 16-105. Delivery services implementation plan. To ensure the safe and orderly implementation of delivery services, each electric utility shall submit to the Commission no later than March 1, 1999, a delivery services implementation plan for non-residential customers and no later than August 1, 2001, a delivery services implementation plan for residential customers. The delivery services implementation plan shall detail the process and procedures by which each electric utility will offer delivery services to each customer class and shall be designed to insure an orderly transition and the maintenance of reliable service. The Commission shall enter an order approving, or approving as modified, the delivery services implementation plan of each electric utility no later than 60 days prior to the date on which the electric utility must commence offering such services.
(Source: P.A. 90-561, eff. 12-16-97.)

    (220 ILCS 5/16-106)
    Sec. 16-106. Billing experiments. During the mandatory transition period, an electric utility may at its discretion conduct one or more experiments for the provision or billing of services on a consolidated or aggregated basis, for the provision of real-time pricing, or other billing or pricing experiments, and may include experimental programs offered to groups of retail customers possessing common attributes as defined by the electric utility, such as the members of an organization that was established to serve a well-defined industry group, companies having multiple sites, or closely located or affiliated buildings, provided that such groups exist for a purpose other than obtaining energy services and have been in existence for at least 10 years. The offering of such a program by an electric utility to retail customers participating in the program, and the participation by those customers in the program, shall not create any right in any other retail customer or group of customers to participate in the same or a similar program. The Commission shall allow such experiments to go into effect upon the filing by the electric utility of a statement describing the program. Nothing contained in this Section shall be deemed to prohibit the electric utility from offering, or the Commission from approving, experimental rates, tariffs and services in addition to those allowed under this Section. The Commission shall review and report annually the progress, participation and effects of such experiments to the General Assembly. Based upon its review, recommendations for modification of such experiments may be made by the Commission to the Illinois General Assembly.
(Source: P.A. 90-561, eff. 12-16-97.)

    (220 ILCS 5/16-107)
    Sec. 16-107. Real-time pricing.
    (a) Each electric utility shall file, on or before May 1, 1998, a tariff or tariffs which allow nonresidential retail customers in the electric utility's service area to elect real-time pricing beginning October 1, 1998.
    (b) Each electric utility shall file, on or before May 1, 2000, a tariff or tariffs which allow residential retail customers in the electric utility's service area to elect real-time pricing beginning October 1, 2000.
    (b-5) Each electric utility shall file a tariff or tariffs allowing residential retail customers in the electric utility's service area to elect real-time pricing beginning January 2, 2007. A customer who elects real-time pricing shall remain on such rate for a minimum of 12 months. The Commission may, after notice and hearing, approve the tariff or tariffs, provided that the Commission finds that the potential for demand reductions will result in net economic benefits to all residential customers of the electric utility. In examining economic benefits from demand reductions, the Commission shall, at a minimum, consider the following: improvements to system reliability and power quality, reduction in wholesale market prices and price volatility, electric utility cost avoidance and reductions, market power mitigation, and other benefits of demand reductions, but only to the extent that the effects of reduced demand can be demonstrated to lower the cost of electricity delivered to residential customers. A tariff or tariffs approved pursuant to this subsection (b-5) shall, at a minimum, describe (i) the methodology for determining the market price of energy to be reflected in the real-time rate and (ii) the manner in which customers who elect real-time pricing will be provided with ready access to hourly market prices, including, but not limited to, day-ahead hourly energy prices.
    A proceeding under this subsection (b-5) may not exceed 120 days in length.
    (b-10) Each electric utility providing real-time pricing pursuant to subsection (b-5) shall install a meter capable of recording hourly interval energy use at the service location of each customer that elects real-time pricing pursuant to this subsection.
    (b-15) If the Commission issues an order pursuant to subsection (b-5), the affected electric utility shall contract with an entity not affiliated with the electric utility to serve as a program administrator to develop and implement a program to provide consumer outreach, enrollment, and education concerning real-time pricing and to establish and administer an information system and technical and other customer assistance that is necessary to enable customers to manage electricity use. The program administrator: (i) shall be selected and compensated by the electric utility, subject to Commission approval; (ii) shall have demonstrated technical and managerial competence in the development and administration of demand management programs; and (iii) may develop and implement risk management, energy efficiency, and other services related to energy use management for which the program administrator shall be compensated by participants in the program receiving such services. The electric utility shall provide the program administrator with all information and assistance necessary to perform the program administrator's duties, including, but not limited to, customer, account, and energy use data. The electric utility shall permit the program administrator to include inserts in residential customer bills 2 times per year to assist with customer outreach and enrollment.
    The program administrator shall submit an annual report to the electric utility no later than April 1 of each year describing the operation and results of the program, including information concerning the number and types of customers using real-time pricing, changes in customers' energy use patterns, an assessment of the value of the program to both participants and non-participants, and recommendations concerning modification of the program and the tariff or tariffs filed under subsection (b-5). This report shall be filed by the electric utility with the Commission within 30 days of receipt and shall be available to the public on the Commission's web site.
    (b-20) The Commission shall monitor the performance of programs established pursuant to subsection (b-15) and shall order the termination or modification of a program if it determines that the program is not, after a reasonable period of time for development not to exceed 4 years, resulting in net benefits to the residential customers of the electric utility.
    (b-25) An electric utility shall be entitled to recover reasonable costs incurred in complying with this Section, provided that recovery of the costs is fairly apportioned among its residential customers as provided in this subsection (b-25). The electric utility may apportion greater costs on the residential customers who elect real-time pricing, but may also impose some of the costs of real-time pricing on customers who do not elect real-time pricing, provided that the Commission determines that the cost savings resulting from real-time pricing will exceed the costs imposed on customers for maintaining the program.
    (c) The electric utility's tariff or tariffs filed pursuant to this Section shall be subject to Article IX.
    (d) This Section does not apply to any electric utility providing service to 100,000 or fewer customers.
(Source: P.A. 94-977, eff. 6-30-06.)

    (220 ILCS 5/16-107.5)
    Sec. 16-107.5. Net electricity metering.
    (a) The Legislature finds and declares that a program to provide net electricity metering, as defined in this Section, for eligible customers can encourage private investment in renewable energy resources, stimulate economic growth, enhance the continued diversification of Illinois' energy resource mix, and protect the Illinois environment.
    (b) As used in this Section, (i) "eligible customer" means a retail customer that owns or operates a solar, wind, or other eligible renewable electrical generating facility with a rated capacity of not more than 2,000 kilowatts that is located on the customer's premises and is intended primarily to offset the customer's own electrical requirements; (ii) "electricity provider" means an electric utility or alternative retail electric supplier; (iii) "eligible renewable electrical generating facility" means a generator powered by solar electric energy, wind, dedicated crops grown for electricity generation, agricultural residues, untreated and unadulterated wood waste, landscape trimmings, livestock manure, anaerobic digestion of livestock or food processing waste, fuel cells or microturbines powered by renewable fuels, or hydroelectric energy; and (iv) "net electricity metering" (or "net metering") means the measurement, during the billing period applicable to an eligible customer, of the net amount of electricity supplied by an electricity provider to the customer's premises or provided to the electricity provider by the customer.
    (c) A net metering facility shall be equipped with metering equipment that can measure the flow of electricity in both directions at the same rate.
        (1) For eligible customers whose electric service has

    
not been declared competitive pursuant to Section 16-113 of this Act as of July 1, 2011 and whose electric delivery service is provided and measured on a kilowatt-hour basis and electric supply service is not provided based on hourly pricing, this shall typically be accomplished through use of a single, bi-directional meter. If the eligible customer's existing electric revenue meter does not meet this requirement, the electricity provider shall arrange for the local electric utility or a meter service provider to install and maintain a new revenue meter at the electricity provider's expense.
        (2) For eligible customers whose electric service has
    
not been declared competitive pursuant to Section 16-113 of this Act as of July 1, 2011 and whose electric delivery service is provided and measured on a kilowatt demand basis and electric supply service is not provided based on hourly pricing, this shall typically be accomplished through use of a dual channel meter capable of measuring the flow of electricity both into and out of the customer's facility at the same rate and ratio. If such customer's existing electric revenue meter does not meet this requirement, then the electricity provider shall arrange for the local electric utility or a meter service provider to install and maintain a new revenue meter at the electricity provider's expense.
        (3) For all other eligible customers, the electricity
    
provider may arrange for the local electric utility or a meter service provider to install and maintain metering equipment capable of measuring the flow of electricity both into and out of the customer's facility at the same rate and ratio, typically through the use of a dual channel meter. If the eligible customer's existing electric revenue meter does not meet this requirement, then the costs of installing such equipment shall be paid for by the customer.
    (d) An electricity provider shall measure and charge or credit for the net electricity supplied to eligible customers or provided by eligible customers whose electric service has not been declared competitive pursuant to Section 16-113 of the Act as of July 1, 2011 and whose electric delivery service is provided and measured on a kilowatt-hour basis and electric supply service is not provided based on hourly pricing in the following manner:
        (1) If the amount of electricity used by the customer
    
during the billing period exceeds the amount of electricity produced by the customer, the electricity provider shall charge the customer for the net electricity supplied to and used by the customer as provided in subsection (e-5) of this Section.
        (2) If the amount of electricity produced by a
    
customer during the billing period exceeds the amount of electricity used by the customer during that billing period, the electricity provider supplying that customer shall apply a 1:1 kilowatt-hour credit to a subsequent bill for service to the customer for the net electricity supplied to the electricity provider. The electricity provider shall continue to carry over any excess kilowatt-hour credits earned and apply those credits to subsequent billing periods to offset any customer-generator consumption in those billing periods until all credits are used or until the end of the annualized period.
        (3) At the end of the year or annualized over the
    
period that service is supplied by means of net metering, or in the event that the retail customer terminates service with the electricity provider prior to the end of the year or the annualized period, any remaining credits in the customer's account shall expire.
    (d-5) An electricity provider shall measure and charge or credit for the net electricity supplied to eligible customers or provided by eligible customers whose electric service has not been declared competitive pursuant to Section 16-113 of this Act as of July 1, 2011 and whose electric delivery service is provided and measured on a kilowatt-hour basis and electric supply service is provided based on hourly pricing in the following manner:
        (1) If the amount of electricity used by the customer
    
during any hourly period exceeds the amount of electricity produced by the customer, the electricity provider shall charge the customer for the net electricity supplied to and used by the customer according to the terms of the contract or tariff to which the same customer would be assigned to or be eligible for if the customer was not a net metering customer.
        (2) If the amount of electricity produced by a
    
customer during any hourly period exceeds the amount of electricity used by the customer during that hourly period, the energy provider shall apply a credit for the net kilowatt-hours produced in such period. The credit shall consist of an energy credit and a delivery service credit. The energy credit shall be valued at the same price per kilowatt-hour as the electric service provider would charge for kilowatt-hour energy sales during that same hourly period. The delivery credit shall be equal to the net kilowatt-hours produced in such hourly period times a credit that reflects all kilowatt-hour based charges in the customer's electric service rate, excluding energy charges.
    (e) An electricity provider shall measure and charge or credit for the net electricity supplied to eligible customers whose electric service has not been declared competitive pursuant to Section 16-113 of this Act as of July 1, 2011 and whose electric delivery service is provided and measured on a kilowatt demand basis and electric supply service is not provided based on hourly pricing in the following manner:
        (1) If the amount of electricity used by the customer
    
during the billing period exceeds the amount of electricity produced by the customer, then the electricity provider shall charge the customer for the net electricity supplied to and used by the customer as provided in subsection (e-5) of this Section. The customer shall remain responsible for all taxes, fees, and utility delivery charges that would otherwise be applicable to the net amount of electricity used by the customer.
        (2) If the amount of electricity produced by a
    
customer during the billing period exceeds the amount of electricity used by the customer during that billing period, then the electricity provider supplying that customer shall apply a 1:1 kilowatt-hour credit that reflects the kilowatt-hour based charges in the customer's electric service rate to a subsequent bill for service to the customer for the net electricity supplied to the electricity provider. The electricity provider shall continue to carry over any excess kilowatt-hour credits earned and apply those credits to subsequent billing periods to offset any customer-generator consumption in those billing periods until all credits are used or until the end of the annualized period.
        (3) At the end of the year or annualized over the
    
period that service is supplied by means of net metering, or in the event that the retail customer terminates service with the electricity provider prior to the end of the year or the annualized period, any remaining credits in the customer's account shall expire.
    (e-5) An electricity provider shall provide electric service to eligible customers who utilize net metering at non-discriminatory rates that are identical, with respect to rate structure, retail rate components, and any monthly charges, to the rates that the customer would be charged if not a net metering customer. An electricity provider shall not charge net metering customers any fee or charge or require additional equipment, insurance, or any other requirements not specifically authorized by interconnection standards authorized by the Commission, unless the fee, charge, or other requirement would apply to other similarly situated customers who are not net metering customers. The customer will remain responsible for all taxes, fees, and utility delivery charges that would otherwise be applicable to the net amount of electricity used by the customer. Subsections (c) through (e) of this Section shall not be construed to prevent an arms-length agreement between an electricity provider and an eligible customer that sets forth different prices, terms, and conditions for the provision of net metering service, including, but not limited to, the provision of the appropriate metering equipment for non-residential customers.
    (f) Notwithstanding the requirements of subsections (c) through (e-5) of this Section, an electricity provider must require dual-channel metering for customers operating eligible renewable electrical generating facilities with a nameplate rating up to 2,000 kilowatts and to whom the provisions of neither subsection (d), (d-5), nor (e) of this Section apply. In such cases, electricity charges and credits shall be determined as follows:
        (1) The electricity provider shall assess and the
    
customer remains responsible for all taxes, fees, and utility delivery charges that would otherwise be applicable to the gross amount of kilowatt-hours supplied to the eligible customer by the electricity provider.
        (2) Each month that service is supplied by means of
    
dual-channel metering, the electricity provider shall compensate the eligible customer for any excess kilowatt-hour credits at the electricity provider's avoided cost of electricity supply over the monthly period or as otherwise specified by the terms of a power-purchase agreement negotiated between the customer and electricity provider.
        (3) For all eligible net metering customers taking
    
service from an electricity provider under contracts or tariffs employing time of use rates, any monthly consumption of electricity shall be calculated according to the terms of the contract or tariff to which the same customer would be assigned to or be eligible for if the customer was not a net metering customer. When those same customer-generators are net generators during any discrete time of use period, the net kilowatt-hours produced shall be valued at the same price per kilowatt-hour as the electric service provider would charge for retail kilowatt-hour sales during that same time of use period.
    (g) For purposes of federal and State laws providing renewable energy credits or greenhouse gas credits, the eligible customer shall be treated as owning and having title to the renewable energy attributes, renewable energy credits, and greenhouse gas emission credits related to any electricity produced by the qualified generating unit. The electricity provider may not condition participation in a net metering program on the signing over of a customer's renewable energy credits; provided, however, this subsection (g) shall not be construed to prevent an arms-length agreement between an electricity provider and an eligible customer that sets forth the ownership or title of the credits.
    (h) Within 120 days after the effective date of this amendatory Act of the 95th General Assembly, the Commission shall establish standards for net metering and, if the Commission has not already acted on its own initiative, standards for the interconnection of eligible renewable generating equipment to the utility system. The interconnection standards shall address any procedural barriers, delays, and administrative costs associated with the interconnection of customer-generation while ensuring the safety and reliability of the units and the electric utility system. The Commission shall consider the Institute of Electrical and Electronics Engineers (IEEE) Standard 1547 and the issues of (i) reasonable and fair fees and costs, (ii) clear timelines for major milestones in the interconnection process, (iii) nondiscriminatory terms of agreement, and (iv) any best practices for interconnection of distributed generation.
    (i) All electricity providers shall begin to offer net metering no later than April 1, 2008.
    (j) An electricity provider shall provide net metering to eligible customers until the load of its net metering customers equals 5% of the total peak demand supplied by that electricity provider during the previous year. Electricity providers are authorized to offer net metering beyond the 5% level if they so choose.
    (k) Each electricity provider shall maintain records and report annually to the Commission the total number of net metering customers served by the provider, as well as the type, capacity, and energy sources of the generating systems used by the net metering customers. Nothing in this Section shall limit the ability of an electricity provider to request the redaction of information deemed by the Commission to be confidential business information. Each electricity provider shall notify the Commission when the total generating capacity of its net metering customers is equal to or in excess of the 5% cap specified in subsection (j) of this Section.
    (l) Notwithstanding the definition of "eligible customer" in item (i) of subsection (b) of this Section, each electricity provider shall consider whether to allow meter aggregation for the purposes of net metering on:
        (1) properties owned or leased by multiple customers
    
that contribute to the operation of an eligible renewable electrical generating facility, such as a community-owned wind project, a community-owned biomass project, a community-owned solar project, or a community methane digester processing livestock waste from multiple sources; and
        (2) individual units, apartments, or properties owned
    
or leased by multiple customers and collectively served by a common eligible renewable electrical generating facility, such as an apartment building served by photovoltaic panels on the roof.
    For the purposes of this subsection (l), "meter aggregation" means the combination of reading and billing on a pro rata basis for the types of eligible customers described in this Section.
    (m) Nothing in this Section shall affect the right of an electricity provider to continue to provide, or the right of a retail customer to continue to receive service pursuant to a contract for electric service between the electricity provider and the retail customer in accordance with the prices, terms, and conditions provided for in that contract. Either the electricity provider or the customer may require compliance with the prices, terms, and conditions of the contract.
(Source: P.A. 97-616, eff. 10-26-11; 97-646, eff. 12-30-11; 97-824, eff. 7-18-12.)

    (220 ILCS 5/16-108)
    Sec. 16-108. Recovery of costs associated with the provision of delivery services.
    (a) An electric utility shall file a delivery services tariff with the Commission at least 210 days prior to the date that it is required to begin offering such services pursuant to this Act. An electric utility shall provide the components of delivery services that are subject to the jurisdiction of the Federal Energy Regulatory Commission at the same prices, terms and conditions set forth in its applicable tariff as approved or allowed into effect by that Commission. The Commission shall otherwise have the authority pursuant to Article IX to review, approve, and modify the prices, terms and conditions of those components of delivery services not subject to the jurisdiction of the Federal Energy Regulatory Commission, including the authority to determine the extent to which such delivery services should be offered on an unbundled basis. In making any such determination the Commission shall consider, at a minimum, the effect of additional unbundling on (i) the objective of just and reasonable rates, (ii) electric utility employees, and (iii) the development of competitive markets for electric energy services in Illinois.
    (b) The Commission shall enter an order approving, or approving as modified, the delivery services tariff no later than 30 days prior to the date on which the electric utility must commence offering such services. The Commission may subsequently modify such tariff pursuant to this Act.
    (c) The electric utility's tariffs shall define the classes of its customers for purposes of delivery services charges. Delivery services shall be priced and made available to all retail customers electing delivery services in each such class on a nondiscriminatory basis regardless of whether the retail customer chooses the electric utility, an affiliate of the electric utility, or another entity as its supplier of electric power and energy. Charges for delivery services shall be cost based, and shall allow the electric utility to recover the costs of providing delivery services through its charges to its delivery service customers that use the facilities and services associated with such costs. Such costs shall include the costs of owning, operating and maintaining transmission and distribution facilities. The Commission shall also be authorized to consider whether, and if so to what extent, the following costs are appropriately included in the electric utility's delivery services rates: (i) the costs of that portion of generation facilities used for the production and absorption of reactive power in order that retail customers located in the electric utility's service area can receive electric power and energy from suppliers other than the electric utility, and (ii) the costs associated with the use and redispatch of generation facilities to mitigate constraints on the transmission or distribution system in order that retail customers located in the electric utility's service area can receive electric power and energy from suppliers other than the electric utility. Nothing in this subsection shall be construed as directing the Commission to allocate any of the costs described in (i) or (ii) that are found to be appropriately included in the electric utility's delivery services rates to any particular customer group or geographic area in setting delivery services rates.
    (d) The Commission shall establish charges, terms and conditions for delivery services that are just and reasonable and shall take into account customer impacts when establishing such charges. In establishing charges, terms and conditions for delivery services, the Commission shall take into account voltage level differences. A retail customer shall have the option to request to purchase electric service at any delivery service voltage reasonably and technically feasible from the electric facilities serving that customer's premises provided that there are no significant adverse impacts upon system reliability or system efficiency. A retail customer shall also have the option to request to purchase electric service at any point of delivery that is reasonably and technically feasible provided that there are no significant adverse impacts on system reliability or efficiency. Such requests shall not be unreasonably denied.
    (e) Electric utilities shall recover the costs of installing, operating or maintaining facilities for the particular benefit of one or more delivery services customers, including without limitation any costs incurred in complying with a customer's request to be served at a different voltage level, directly from the retail customer or customers for whose benefit the costs were incurred, to the extent such costs are not recovered through the charges referred to in subsections (c) and (d) of this Section.
    (f) An electric utility shall be entitled but not required to implement transition charges in conjunction with the offering of delivery services pursuant to Section 16-104. If an electric utility implements transition charges, it shall implement such charges for all delivery services customers and for all customers described in subsection (h), but shall not implement transition charges for power and energy that a retail customer takes from cogeneration or self-generation facilities located on that retail customer's premises, if such facilities meet the following criteria:
        (i) the cogeneration or self-generation facilities

    
serve a single retail customer and are located on that retail customer's premises (for purposes of this subparagraph and subparagraph (ii), an industrial or manufacturing retail customer and a third party contractor that is served by such industrial or manufacturing customer through such retail customer's own electrical distribution facilities under the circumstances described in subsection (vi) of the definition of "alternative retail electric supplier" set forth in Section 16-102, shall be considered a single retail customer);
        (ii) the cogeneration or self-generation facilities
    
either (A) are sized pursuant to generally accepted engineering standards for the retail customer's electrical load at that premises (taking into account standby or other reliability considerations related to that retail customer's operations at that site) or (B) if the facility is a cogeneration facility located on the retail customer's premises, the retail customer is the thermal host for that facility and the facility has been designed to meet that retail customer's thermal energy requirements resulting in electrical output beyond that retail customer's electrical demand at that premises, comply with the operating and efficiency standards applicable to "qualifying facilities" specified in title 18 Code of Federal Regulations Section 292.205 as in effect on the effective date of this amendatory Act of 1999;
        (iii) the retail customer on whose premises the
    
facilities are located either has an exclusive right to receive, and corresponding obligation to pay for, all of the electrical capacity of the facility, or in the case of a cogeneration facility that has been designed to meet the retail customer's thermal energy requirements at that premises, an identified amount of the electrical capacity of the facility, over a minimum 5-year period; and
        (iv) if the cogeneration facility is sized for the
    
retail customer's thermal load at that premises but exceeds the electrical load, any sales of excess power or energy are made only at wholesale, are subject to the jurisdiction of the Federal Energy Regulatory Commission, and are not for the purpose of circumventing the provisions of this subsection (f).
If a generation facility located at a retail customer's premises does not meet the above criteria, an electric utility implementing transition charges shall implement a transition charge until December 31, 2006 for any power and energy taken by such retail customer from such facility as if such power and energy had been delivered by the electric utility. Provided, however, that an industrial retail customer that is taking power from a generation facility that does not meet the above criteria but that is located on such customer's premises will not be subject to a transition charge for the power and energy taken by such retail customer from such generation facility if the facility does not serve any other retail customer and either was installed on behalf of the customer and for its own use prior to January 1, 1997, or is both predominantly fueled by byproducts of such customer's manufacturing process at such premises and sells or offers an average of 300 megawatts or more of electricity produced from such generation facility into the wholesale market. Such charges shall be calculated as provided in Section 16-102, and shall be collected on each kilowatt-hour delivered under a delivery services tariff to a retail customer from the date the customer first takes delivery services until December 31, 2006 except as provided in subsection (h) of this Section. Provided, however, that an electric utility, other than an electric utility providing service to at least 1,000,000 customers in this State on January 1, 1999, shall be entitled to petition for entry of an order by the Commission authorizing the electric utility to implement transition charges for an additional period ending no later than December 31, 2008. The electric utility shall file its petition with supporting evidence no earlier than 16 months, and no later than 12 months, prior to December 31, 2006. The Commission shall hold a hearing on the electric utility's petition and shall enter its order no later than 8 months after the petition is filed. The Commission shall determine whether and to what extent the electric utility shall be authorized to implement transition charges for an additional period. The Commission may authorize the electric utility to implement transition charges for some or all of the additional period, and shall determine the mitigation factors to be used in implementing such transition charges; provided, that the Commission shall not authorize mitigation factors less than 110% of those in effect during the 12 months ended December 31, 2006. In making its determination, the Commission shall consider the following factors: the necessity to implement transition charges for an additional period in order to maintain the financial integrity of the electric utility; the prudence of the electric utility's actions in reducing its costs since the effective date of this amendatory Act of 1997; the ability of the electric utility to provide safe, adequate and reliable service to retail customers in its service area; and the impact on competition of allowing the electric utility to implement transition charges for the additional period.
    (g) The electric utility shall file tariffs that establish the transition charges to be paid by each class of customers to the electric utility in conjunction with the provision of delivery services. The electric utility's tariffs shall define the classes of its customers for purposes of calculating transition charges. The electric utility's tariffs shall provide for the calculation of transition charges on a customer-specific basis for any retail customer whose average monthly maximum electrical demand on the electric utility's system during the 6 months with the customer's highest monthly maximum electrical demands equals or exceeds 3.0 megawatts for electric utilities having more than 1,000,000 customers, and for other electric utilities for any customer that has an average monthly maximum electrical demand on the electric utility's system of one megawatt or more, and (A) for which there exists data on the customer's usage during the 3 years preceding the date that the customer became eligible to take delivery services, or (B) for which there does not exist data on the customer's usage during the 3 years preceding the date that the customer became eligible to take delivery services, if in the electric utility's reasonable judgment there exists comparable usage information or a sufficient basis to develop such information, and further provided that the electric utility can require customers for which an individual calculation is made to sign contracts that set forth the transition charges to be paid by the customer to the electric utility pursuant to the tariff.
    (h) An electric utility shall also be entitled to file tariffs that allow it to collect transition charges from retail customers in the electric utility's service area that do not take delivery services but that take electric power or energy from an alternative retail electric supplier or from an electric utility other than the electric utility in whose service area the customer is located. Such charges shall be calculated, in accordance with the definition of transition charges in Section 16-102, for the period of time that the customer would be obligated to pay transition charges if it were taking delivery services, except that no deduction for delivery services revenues shall be made in such calculation, and usage data from the customer's class shall be used where historical usage data is not available for the individual customer. The customer shall be obligated to pay such charges on a lump sum basis on or before the date on which the customer commences to take service from the alternative retail electric supplier or other electric utility, provided, that the electric utility in whose service area the customer is located shall offer the customer the option of signing a contract pursuant to which the customer pays such charges ratably over the period in which the charges would otherwise have applied.
    (i) An electric utility shall be entitled to add to the bills of delivery services customers charges pursuant to Sections 9-221, 9-222 (except as provided in Section 9-222.1), and Section 16-114 of this Act, Section 5-5 of the Electricity Infrastructure Maintenance Fee Law, Section 6-5 of the Renewable Energy, Energy Efficiency, and Coal Resources Development Law of 1997, and Section 13 of the Energy Assistance Act.
    (j) If a retail customer that obtains electric power and energy from cogeneration or self-generation facilities installed for its own use on or before January 1, 1997, subsequently takes service from an alternative retail electric supplier or an electric utility other than the electric utility in whose service area the customer is located for any portion of the customer's electric power and energy requirements formerly obtained from those facilities (including that amount purchased from the utility in lieu of such generation and not as standby power purchases, under a cogeneration displacement tariff in effect as of the effective date of this amendatory Act of 1997), the transition charges otherwise applicable pursuant to subsections (f), (g), or (h) of this Section shall not be applicable in any year to that portion of the customer's electric power and energy requirements formerly obtained from those facilities, provided, that for purposes of this subsection (j), such portion shall not exceed the average number of kilowatt-hours per year obtained from the cogeneration or self-generation facilities during the 3 years prior to the date on which the customer became eligible for delivery services, except as provided in subsection (f) of Section 16-110.
(Source: P.A. 91-50, eff. 6-30-99; 92-690, eff. 7-18-02.)

    (220 ILCS 5/16-108.5)
    Sec. 16-108.5. Infrastructure investment and modernization; regulatory reform.
    (a) (Blank).
    (b) For purposes of this Section, "participating utility" means an electric utility or a combination utility serving more than 1,000,000 customers in Illinois that voluntarily elects and commits to undertake (i) the infrastructure investment program consisting of the commitments and obligations described in this subsection (b) and (ii) the customer assistance program consisting of the commitments and obligations described in subsection (b-10) of this Section, notwithstanding any other provisions of this Act and without obtaining any approvals from the Commission or any other agency other than as set forth in this Section, regardless of whether any such approval would otherwise be required. "Combination utility" means a utility that, as of January 1, 2011, provided electric service to at least one million retail customers in Illinois and gas service to at least 500,000 retail customers in Illinois. A participating utility shall recover the expenditures made under the infrastructure investment program through the ratemaking process, including, but not limited to, the performance-based formula rate and process set forth in this Section.
    During the infrastructure investment program's peak program year, a participating utility other than a combination utility shall create 2,000 full-time equivalent jobs in Illinois, and a participating utility that is a combination utility shall create 450 full-time equivalent jobs in Illinois related to the provision of electric service. These jobs shall include direct jobs, contractor positions, and induced jobs, but shall not include any portion of a job commitment, not specifically contingent on an amendatory Act of the 97th General Assembly becoming law, between a participating utility and a labor union that existed on the effective date of this amendatory Act of the 97th General Assembly and that has not yet been fulfilled. A portion of the full-time equivalent jobs created by each participating utility shall include incremental personnel hired subsequent to the effective date of this amendatory Act of the 97th General Assembly. For purposes of this Section, "peak program year" means the consecutive 12-month period with the highest number of full-time equivalent jobs that occurs between the beginning of investment year 2 and the end of investment year 4.
    A participating utility shall meet one of the following commitments, as applicable:
        (1) Beginning no later than 180 days after a

    
participating utility other than a combination utility files a performance-based formula rate tariff pursuant to subsection (c) of this Section, or, beginning no later than January 1, 2012 if such utility files such performance-based formula rate tariff within 14 days of the effective date of this amendatory Act of the 97th General Assembly, the participating utility shall, except as provided in subsection (b-5):
            (A) over a 5-year period, invest an estimated
        
$1,300,000,000 in electric system upgrades, modernization projects, and training facilities, including, but not limited to:
                (i) distribution infrastructure improvements
            
totaling an estimated $1,000,000,000, including underground residential distribution cable injection and replacement and mainline cable system refurbishment and replacement projects;
                (ii) training facility construction or
            
upgrade projects totaling an estimated $10,000,000, provided that, at a minimum, one such facility shall be located in a municipality having a population of more than 2 million residents and one such facility shall be located in a municipality having a population of more than 150,000 residents but fewer than 170,000 residents; any such new facility located in a municipality having a population of more than 2 million residents must be designed for the purpose of obtaining, and the owner of the facility shall apply for, certification under the United States Green Building Council's Leadership in Energy Efficiency Design Green Building Rating System;
                (iii) wood pole inspection, treatment, and
            
replacement programs;
                (iv) an estimated $200,000,000 for reducing
            
the susceptibility of certain circuits to storm-related damage, including, but not limited to, high winds, thunderstorms, and ice storms; improvements may include, but are not limited to, overhead to underground conversion and other engineered outcomes for circuits; the participating utility shall prioritize the selection of circuits based on each circuit's historical susceptibility to storm-related damage and the ability to provide the greatest customer benefit upon completion of the improvements; to be eligible for improvement, the participating utility's ability to maintain proper tree clearances surrounding the overhead circuit must not have been impeded by third parties; and
            (B) over a 10-year period, invest an estimated
        
$1,300,000,000 to upgrade and modernize its transmission and distribution infrastructure and in Smart Grid electric system upgrades, including, but not limited to:
                (i) additional smart meters;
                (ii) distribution automation;
                (iii) associated cyber secure data
            
communication network; and
                (iv) substation micro-processor relay
            
upgrades.
        (2) Beginning no later than 180 days after a
    
participating utility that is a combination utility files a performance-based formula rate tariff pursuant to subsection (c) of this Section, or, beginning no later than January 1, 2012 if such utility files such performance-based formula rate tariff within 14 days of the effective date of this amendatory Act of the 97th General Assembly, the participating utility shall, except as provided in subsection (b-5):
            (A) over a 10-year period, invest an estimated
        
$265,000,000 in electric system upgrades, modernization projects, and training facilities, including, but not limited to:
                (i) distribution infrastructure improvements
            
totaling an estimated $245,000,000, which may include bulk supply substations, transformers, reconductoring, and rebuilding overhead distribution and sub-transmission lines, underground residential distribution cable injection and replacement and mainline cable system refurbishment and replacement projects;
                (ii) training facility construction or
            
upgrade projects totaling an estimated $1,000,000; any such new facility must be designed for the purpose of obtaining, and the owner of the facility shall apply for, certification under the United States Green Building Council's Leadership in Energy Efficiency Design Green Building Rating System; and
                (iii) wood pole inspection, treatment, and
            
replacement programs; and
            (B) over a 10-year period, invest an estimated
        
$360,000,000 to upgrade and modernize its transmission and distribution infrastructure and in Smart Grid electric system upgrades, including, but not limited to:
                (i) additional smart meters;
                (ii) distribution automation;
                (iii) associated cyber secure data
            
communication network; and
                (iv) substation micro-processor relay
            
upgrades.
    For purposes of this Section, "Smart Grid electric system upgrades" shall have the meaning set forth in subsection (a) of Section 16-108.6 of this Act.
    The investments in the infrastructure investment program described in this subsection (b) shall be incremental to the participating utility's annual capital investment program, as defined by, for purposes of this subsection (b), the participating utility's average capital spend for calendar years 2008, 2009, and 2010 as reported in the applicable Federal Energy Regulatory Commission (FERC) Form 1; provided that where one or more utilities have merged, the average capital spend shall be determined using the aggregate of the merged utilities' capital spend reported in FERC Form 1 for the years 2008, 2009, and 2010. A participating utility may add reasonable construction ramp-up and ramp-down time to the investment periods specified in this subsection (b). For each such investment period, the ramp-up and ramp-down time shall not exceed a total of 6 months.
    Within 60 days after filing a tariff under subsection (c) of this Section, a participating utility shall submit to the Commission its plan, including scope, schedule, and staffing, for satisfying its infrastructure investment program commitments pursuant to this subsection (b). The submitted plan shall include a schedule and staffing plan for the next calendar year. The plan shall also include a plan for the creation, operation, and administration of a Smart Grid test bed as described in subsection (c) of Section 16-108.8. The plan need not allocate the work equally over the respective periods, but should allocate material increments throughout such periods commensurate with the work to be undertaken. No later than April 1 of each subsequent year, the utility shall submit to the Commission a report that includes any updates to the plan, a schedule for the next calendar year, the expenditures made for the prior calendar year and cumulatively, and the number of full-time equivalent jobs created for the prior calendar year and cumulatively. If the utility is materially deficient in satisfying a schedule or staffing plan, then the report must also include a corrective action plan to address the deficiency. The fact that the plan, implementation of the plan, or a schedule changes shall not imply the imprudence or unreasonableness of the infrastructure investment program, plan, or schedule. Further, no later than 45 days following the last day of the first, second, and third quarters of each year of the plan, a participating utility shall submit to the Commission a verified quarterly report for the prior quarter that includes (i) the total number of full-time equivalent jobs created during the prior quarter, (ii) the total number of employees as of the last day of the prior quarter, (iii) the total number of full-time equivalent hours in each job classification or job title, (iv) the total number of incremental employees and contractors in support of the investments undertaken pursuant to this subsection (b) for the prior quarter, and (v) any other information that the Commission may require by rule.
    With respect to the participating utility's peak job commitment, if, after considering the utility's corrective action plan and compliance thereunder, the Commission enters an order finding, after notice and hearing, that a participating utility did not satisfy its peak job commitment described in this subsection (b) for reasons that are reasonably within its control, then the Commission shall also determine, after consideration of the evidence, including, but not limited to, evidence submitted by the Department of Commerce and Economic Opportunity and the utility, the deficiency in the number of full-time equivalent jobs during the peak program year due to such failure. The Commission shall notify the Department of any proceeding that is initiated pursuant to this paragraph. For each full-time equivalent job deficiency during the peak program year that the Commission finds as set forth in this paragraph, the participating utility shall, within 30 days after the entry of the Commission's order, pay $6,000 to a fund for training grants administered under Section 605-800 of The Department of Commerce and Economic Opportunity Law, which shall not be a recoverable expense.
    With respect to the participating utility's investment amount commitments, if, after considering the utility's corrective action plan and compliance thereunder, the Commission enters an order finding, after notice and hearing, that a participating utility is not satisfying its investment amount commitments described in this subsection (b), then the utility shall no longer be eligible to annually update the performance-based formula rate tariff pursuant to subsection (d) of this Section. In such event, the then current rates shall remain in effect until such time as new rates are set pursuant to Article IX of this Act, subject to retroactive adjustment, with interest, to reconcile rates charged with actual costs.
    If the Commission finds that a participating utility is no longer eligible to update the performance-based formula rate tariff pursuant to subsection (d) of this Section, or the performance-based formula rate is otherwise terminated, then the participating utility's voluntary commitments and obligations under this subsection (b) shall immediately terminate, except for the utility's obligation to pay an amount already owed to the fund for training grants pursuant to a Commission order.
    In meeting the obligations of this subsection (b), to the extent feasible and consistent with State and federal law, the investments under the infrastructure investment program should provide employment opportunities for all segments of the population and workforce, including minority-owned and female-owned business enterprises, and shall not, consistent with State and federal law, discriminate based on race or socioeconomic status.
    (b-5) Nothing in this Section shall prohibit the Commission from investigating the prudence and reasonableness of the expenditures made under the infrastructure investment program during the annual review required by subsection (d) of this Section and shall, as part of such investigation, determine whether the utility's actual costs under the program are prudent and reasonable. The fact that a participating utility invests more than the minimum amounts specified in subsection (b) of this Section or its plan shall not imply imprudence or unreasonableness.
    If the participating utility finds that it is implementing its plan for satisfying the infrastructure investment program commitments described in subsection (b) of this Section at a cost below the estimated amounts specified in subsection (b) of this Section, then the utility may file a petition with the Commission requesting that it be permitted to satisfy its commitments by spending less than the estimated amounts specified in subsection (b) of this Section. The Commission shall, after notice and hearing, enter its order approving, or approving as modified, or denying each such petition within 150 days after the filing of the petition.
    In no event, absent General Assembly approval, shall the capital investment costs incurred by a participating utility other than a combination utility in satisfying its infrastructure investment program commitments described in subsection (b) of this Section exceed $3,000,000,000 or, for a participating utility that is a combination utility, $720,000,000. If the participating utility's updated cost estimates for satisfying its infrastructure investment program commitments described in subsection (b) of this Section exceed the limitation imposed by this subsection (b-5), then it shall submit a report to the Commission that identifies the increased costs and explains the reason or reasons for the increased costs no later than the year in which the utility estimates it will exceed the limitation. The Commission shall review the report and shall, within 90 days after the participating utility files the report, report to the General Assembly its findings regarding the participating utility's report. If the General Assembly does not amend the limitation imposed by this subsection (b-5), then the utility may modify its plan so as not to exceed the limitation imposed by this subsection (b-5) and may propose corresponding changes to the metrics established pursuant to subparagraphs (5) through (8) of subsection (f) of this Section, and the Commission may modify the metrics and incremental savings goals established pursuant to subsection (f) of this Section accordingly.
    (b-10) All participating utilities shall make contributions for an energy low-income and support program in accordance with this subsection. Beginning no later than 180 days after a participating utility files a performance-based formula rate tariff pursuant to subsection (c) of this Section, or beginning no later than January 1, 2012 if such utility files such performance-based formula rate tariff within 14 days of the effective date of this amendatory Act of the 97th General Assembly, and without obtaining any approvals from the Commission or any other agency other than as set forth in this Section, regardless of whether any such approval would otherwise be required, a participating utility other than a combination utility shall pay $10,000,000 per year for 5 years and a participating utility that is a combination utility shall pay $1,000,000 per year for 10 years to the energy low-income and support program, which is intended to fund customer assistance programs with the primary purpose being avoidance of imminent disconnection. Such programs may include:
        (1) a residential hardship program that may partner
    
with community-based organizations, including senior citizen organizations, and provides grants to low-income residential customers, including low-income senior citizens, who demonstrate a hardship;
        (2) a program that provides grants and other bill
    
payment concessions to disabled veterans who demonstrate a hardship and members of the armed services or reserve forces of the United States or members of the Illinois National Guard who are on active duty pursuant to an executive order of the President of the United States, an act of the Congress of the United States, or an order of the Governor and who demonstrate a hardship;
        (3) a budget assistance program that provides tools
    
and education to low-income senior citizens to assist them with obtaining information regarding energy usage and effective means of managing energy costs;
        (4) a non-residential special hardship program that
    
provides grants to non-residential customers such as small businesses and non-profit organizations that demonstrate a hardship, including those providing services to senior citizen and low-income customers; and
        (5) a performance-based assistance program that
    
provides grants to encourage residential customers to make on-time payments by matching a portion of the customer's payments or providing credits towards arrearages.
    The payments made by a participating utility pursuant to this subsection (b-10) shall not be a recoverable expense. A participating utility may elect to fund either new or existing customer assistance programs, including, but not limited to, those that are administered by the utility.
    Programs that use funds that are provided by a participating utility to reduce utility bills may be implemented through tariffs that are filed with and reviewed by the Commission. If a utility elects to file tariffs with the Commission to implement all or a portion of the programs, those tariffs shall, regardless of the date actually filed, be deemed accepted and approved, and shall become effective on the effective date of this amendatory Act of the 97th General Assembly. The participating utilities whose customers benefit from the funds that are disbursed as contemplated in this Section shall file annual reports documenting the disbursement of those funds with the Commission. The Commission has the authority to audit disbursement of the funds to ensure they were disbursed consistently with this Section.
    If the Commission finds that a participating utility is no longer eligible to update the performance-based formula rate tariff pursuant to subsection (d) of this Section, or the performance-based formula rate is otherwise terminated, then the participating utility's voluntary commitments and obligations under this subsection (b-10) shall immediately terminate.
    (c) A participating utility may elect to recover its delivery services costs through a performance-based formula rate approved by the Commission, which shall specify the cost components that form the basis of the rate charged to customers with sufficient specificity to operate in a standardized manner and be updated annually with transparent information that reflects the utility's actual costs to be recovered during the applicable rate year, which is the period beginning with the first billing day of January and extending through the last billing day of the following December. In the event the utility recovers a portion of its costs through automatic adjustment clause tariffs on the effective date of this amendatory Act of the 97th General Assembly, the utility may elect to continue to recover these costs through such tariffs, but then these costs shall not be recovered through the performance-based formula rate. In the event the participating utility, prior to the effective date of this amendatory Act of the 97th General Assembly, filed electric delivery services tariffs with the Commission pursuant to Section 9-201 of this Act that are related to the recovery of its electric delivery services costs that are still pending on the effective date of this amendatory Act of the 97th General Assembly, the participating utility shall, at the time it files its performance-based formula rate tariff with the Commission, also file a notice of withdrawal with the Commission to withdraw the electric delivery services tariffs previously filed pursuant to Section 9-201 of this Act. Upon receipt of such notice, the Commission shall dismiss with prejudice any docket that had been initiated to investigate the electric delivery services tariffs filed pursuant to Section 9-201 of this Act, and such tariffs and the record related thereto shall not be the subject of any further hearing, investigation, or proceeding of any kind related to rates for electric delivery services.
    The performance-based formula rate shall be implemented through a tariff filed with the Commission consistent with the provisions of this subsection (c) that shall be applicable to all delivery services customers. The Commission shall initiate and conduct an investigation of the tariff in a manner consistent with the provisions of this subsection (c) and the provisions of Article IX of this Act to the extent they do not conflict with this subsection (c). Except in the case where the Commission finds, after notice and hearing, that a participating utility is not satisfying its investment amount commitments under subsection (b) of this Section, the performance-based formula rate shall remain in effect at the discretion of the utility. The performance-based formula rate approved by the Commission shall do the following:
        (1) Provide for the recovery of the utility's actual
    
costs of delivery services that are prudently incurred and reasonable in amount consistent with Commission practice and law. The sole fact that a cost differs from that incurred in a prior calendar year or that an investment is different from that made in a prior calendar year shall not imply the imprudence or unreasonableness of that cost or investment.
        (2) Reflect the utility's actual year-end capital
    
structure for the applicable calendar year, excluding goodwill, subject to a determination of prudence and reasonableness consistent with Commission practice and law.
        (3) Include a cost of equity, which shall be
    
calculated as the sum of the following:
            (A) the average for the applicable calendar year
        
of the monthly average yields of 30-year U.S. Treasury bonds published by the Board of Governors of the Federal Reserve System in its weekly H.15 Statistical Release or successor publication; and
            (B) 580 basis points.
        At such time as the Board of Governors of the Federal
    
Reserve System ceases to include the monthly average yields of 30-year U.S. Treasury bonds in its weekly H.15 Statistical Release or successor publication, the monthly average yields of the U.S. Treasury bonds then having the longest duration published by the Board of Governors in its weekly H.15 Statistical Release or successor publication shall instead be used for purposes of this paragraph (3).
        (4) Permit and set forth protocols, subject to a
    
determination of prudence and reasonableness consistent with Commission practice and law, for the following:
            (A) recovery of incentive compensation expense
        
that is based on the achievement of operational metrics, including metrics related to budget controls, outage duration and frequency, safety, customer service, efficiency and productivity, and environmental compliance. Incentive compensation expense that is based on net income or an affiliate's earnings per share shall not be recoverable under the performance-based formula rate;
            (B) recovery of pension and other post-employment
        
benefits expense, provided that such costs are supported by an actuarial study;
            (C) recovery of severance costs, provided that if
        
the amount is over $3,700,000 for a participating utility that is a combination utility or $10,000,000 for a participating utility that serves more than 3 million retail customers, then the full amount shall be amortized consistent with subparagraph (F) of this paragraph (4);
            (D) investment return at a rate equal to the
        
utility's weighted average cost of long-term debt, on the pension assets as, and in the amount, reported in Account 186 (or in such other Account or Accounts as such asset may subsequently be recorded) of the utility's most recently filed FERC Form 1, net of deferred tax benefits;
            (E) recovery of the expenses related to the
        
Commission proceeding under this subsection (c) to approve this performance-based formula rate and initial rates or to subsequent proceedings related to the formula, provided that the recovery shall be amortized over a 3-year period; recovery of expenses related to the annual Commission proceedings under subsection (d) of this Section to review the inputs to the performance-based formula rate shall be expensed and recovered through the performance-based formula rate;
            (F) amortization over a 5-year period of the full
        
amount of each charge or credit that exceeds $3,700,000 for a participating utility that is a combination utility or $10,000,000 for a participating utility that serves more than 3 million retail customers in the applicable calendar year and that relates to a workforce reduction program's severance costs, changes in accounting rules, changes in law, compliance with any Commission-initiated audit, or a single storm or other similar expense, provided that any unamortized balance shall be reflected in rate base. For purposes of this subparagraph (F), changes in law includes any enactment, repeal, or amendment in a law, ordinance, rule, regulation, interpretation, permit, license, consent, or order, including those relating to taxes, accounting, or to environmental matters, or in the interpretation or application thereof by any governmental authority occurring after the effective date of this amendatory Act of the 97th General Assembly;
            (G) recovery of existing regulatory assets over
        
the periods previously authorized by the Commission;
            (H) historical weather normalized billing
        
determinants; and
            (I) allocation methods for common costs.
        (5) Provide that if the participating utility's
    
earned rate of return on common equity related to the provision of delivery services for the prior rate year (calculated using costs and capital structure approved by the Commission as provided in subparagraph (2) of this subsection (c), consistent with this Section, in accordance with Commission rules and orders, including, but not limited to, adjustments for goodwill, and after any Commission-ordered disallowances and taxes) is more than 50 basis points higher than the rate of return on common equity calculated pursuant to paragraph (3) of this subsection (c) (after adjusting for any penalties to the rate of return on common equity applied pursuant to the performance metrics provision of subsection (f) of this Section), then the participating utility shall apply a credit through the performance-based formula rate that reflects an amount equal to the value of that portion of the earned rate of return on common equity that is more than 50 basis points higher than the rate of return on common equity calculated pursuant to paragraph (3) of this subsection (c) (after adjusting for any penalties to the rate of return on common equity applied pursuant to the performance metrics provision of subsection (f) of this Section) for the prior rate year, adjusted for taxes. If the participating utility's earned rate of return on common equity related to the provision of delivery services for the prior rate year (calculated using costs and capital structure approved by the Commission as provided in subparagraph (2) of this subsection (c), consistent with this Section, in accordance with Commission rules and orders, including, but not limited to, adjustments for goodwill, and after any Commission-ordered disallowances and taxes) is more than 50 basis points less than the return on common equity calculated pursuant to paragraph (3) of this subsection (c) (after adjusting for any penalties to the rate of return on common equity applied pursuant to the performance metrics provision of subsection (f) of this Section), then the participating utility shall apply a charge through the performance-based formula rate that reflects an amount equal to the value of that portion of the earned rate of return on common equity that is more than 50 basis points less than the rate of return on common equity calculated pursuant to paragraph (3) of this subsection (c) (after adjusting for any penalties to the rate of return on common equity applied pursuant to the performance metrics provision of subsection (f) of this Section) for the prior rate year, adjusted for taxes.
        (6) Provide for an annual reconciliation, as
    
described in subsection (d) of this Section, with interest, of the revenue requirement reflected in rates for each calendar year, beginning with the calendar year in which the utility files its performance-based formula rate tariff pursuant to subsection (c) of this Section, with what the revenue requirement would have been had the actual cost information for the applicable calendar year been available at the filing date.
    The utility shall file, together with its tariff, final data based on its most recently filed FERC Form 1, plus projected plant additions and correspondingly updated depreciation reserve and expense for the calendar year in which the tariff and data are filed, that shall populate the performance-based formula rate and set the initial delivery services rates under the formula. For purposes of this Section, "FERC Form 1" means the Annual Report of Major Electric Utilities, Licensees and Others that electric utilities are required to file with the Federal Energy Regulatory Commission under the Federal Power Act, Sections 3, 4(a), 304 and 209, modified as necessary to be consistent with 83 Ill. Admin. Code Part 415 as of May 1, 2011. Nothing in this Section is intended to allow costs that are not otherwise recoverable to be recoverable by virtue of inclusion in FERC Form 1.
    After the utility files its proposed performance-based formula rate structure and protocols and initial rates, the Commission shall initiate a docket to review the filing. The Commission shall enter an order approving, or approving as modified, the performance-based formula rate, including the initial rates, as just and reasonable within 270 days after the date on which the tariff was filed, or, if the tariff is filed within 14 days after the effective date of this amendatory Act of the 97th General Assembly, then by May 31, 2012. Such review shall be based on the same evidentiary standards, including, but not limited to, those concerning the prudence and reasonableness of the costs incurred by the utility, the Commission applies in a hearing to review a filing for a general increase in rates under Article IX of this Act. The initial rates shall take effect within 30 days after the Commission's order approving the performance-based formula rate tariff.
    Until such time as the Commission approves a different rate design and cost allocation pursuant to subsection (e) of this Section, rate design and cost allocation across customer classes shall be consistent with the Commission's most recent order regarding the participating utility's request for a general increase in its delivery services rates.
    Subsequent changes to the performance-based formula rate structure or protocols shall be made as set forth in Section 9-201 of this Act, but nothing in this subsection (c) is intended to limit the Commission's authority under Article IX and other provisions of this Act to initiate an investigation of a participating utility's performance-based formula rate tariff, provided that any such changes shall be consistent with paragraphs (1) through (6) of this subsection (c). Any change ordered by the Commission shall be made at the same time new rates take effect following the Commission's next order pursuant to subsection (d) of this Section, provided that the new rates take effect no less than 30 days after the date on which the Commission issues an order adopting the change.
    A participating utility that files a tariff pursuant to this subsection (c) must submit a one-time $200,000 filing fee at the time the Chief Clerk of the Commission accepts the filing, which shall be a recoverable expense.
    In the event the performance-based formula rate is terminated, the then current rates shall remain in effect until such time as new rates are set pursuant to Article IX of this Act, subject to retroactive rate adjustment, with interest, to reconcile rates charged with actual costs. At such time that the performance-based formula rate is terminated, the participating utility's voluntary commitments and obligations under subsection (b) of this Section shall immediately terminate, except for the utility's obligation to pay an amount already owed to the fund for training grants pursuant to a Commission order issued under subsection (b) of this Section.
    (d) Subsequent to the Commission's issuance of an order approving the utility's performance-based formula rate structure and protocols, and initial rates under subsection (c) of this Section, the utility shall file, on or before May 1 of each year, with the Chief Clerk of the Commission its updated cost inputs to the performance-based formula rate for the applicable rate year and the corresponding new charges. Each such filing shall conform to the following requirements and include the following information:
        (1) The inputs to the performance-based formula rate
    
for the applicable rate year shall be based on final historical data reflected in the utility's most recently filed annual FERC Form 1 plus projected plant additions and correspondingly updated depreciation reserve and expense for the calendar year in which the inputs are filed. The filing shall also include a reconciliation of the revenue requirement that was in effect for the prior rate year (as set by the cost inputs for the prior rate year) with the actual revenue requirement for the prior rate year (determined using a year-end rate base) that uses amounts reflected in the applicable FERC Form 1 that reports the actual costs for the prior rate year. Any over-collection or under-collection indicated by such reconciliation shall be reflected as a credit against, or recovered as an additional charge to, respectively, with interest calculated at a rate equal to the utility's weighted average cost of capital approved by the Commission for the prior rate year, the charges for the applicable rate year. Provided, however, that the first such reconciliation shall be for the calendar year in which the utility files its performance-based formula rate tariff pursuant to subsection (c) of this Section and shall reconcile (i) the revenue requirement or requirements established by the rate order or orders in effect from time to time during such calendar year (weighted, as applicable) with (ii) the revenue requirement determined using a year-end rate base for that calendar year calculated pursuant to the performance-based formula rate using (A) actual costs for that year as reflected in the applicable FERC Form 1, and (B) for the first such reconciliation only, the cost of equity, which shall be calculated as the sum of 590 basis points plus the average for the applicable calendar year of the monthly average yields of 30-year U.S. Treasury bonds published by the Board of Governors of the Federal Reserve System in its weekly H.15 Statistical Release or successor publication. The first such reconciliation is not intended to provide for the recovery of costs previously excluded from rates based on a prior Commission order finding of imprudence or unreasonableness. Each reconciliation shall be certified by the participating utility in the same manner that FERC Form 1 is certified. The filing shall also include the charge or credit, if any, resulting from the calculation required by paragraph (6) of subsection (c) of this Section.
        Notwithstanding anything that may be to the contrary,
    
the intent of the reconciliation is to ultimately reconcile the revenue requirement reflected in rates for each calendar year, beginning with the calendar year in which the utility files its performance-based formula rate tariff pursuant to subsection (c) of this Section, with what the revenue requirement determined using a year-end rate base for the applicable calendar year would have been had the actual cost information for the applicable calendar year been available at the filing date.
        (2) The new charges shall take effect beginning on
    
the first billing day of the following January billing period and remain in effect through the last billing day of the next December billing period regardless of whether the Commission enters upon a hearing pursuant to this subsection (d).
        (3) The filing shall include relevant and necessary
    
data and documentation for the applicable rate year that is consistent with the Commission's rules applicable to a filing for a general increase in rates or any rules adopted by the Commission to implement this Section. Normalization adjustments shall not be required. Notwithstanding any other provision of this Section or Act or any rule or other requirement adopted by the Commission, a participating utility that is a combination utility with more than one rate zone shall not be required to file a separate set of such data and documentation for each rate zone and may combine such data and documentation into a single set of schedules.
    Within 45 days after the utility files its annual update of cost inputs to the performance-based formula rate, the Commission shall have the authority, either upon complaint or its own initiative, but with reasonable notice, to enter upon a hearing concerning the prudence and reasonableness of the costs incurred by the utility to be recovered during the applicable rate year that are reflected in the inputs to the performance-based formula rate derived from the utility's FERC Form 1. During the course of the hearing, each objection shall be stated with particularity and evidence provided in support thereof, after which the utility shall have the opportunity to rebut the evidence. Discovery shall be allowed consistent with the Commission's Rules of Practice, which Rules shall be enforced by the Commission or the assigned hearing examiner. The Commission shall apply the same evidentiary standards, including, but not limited to, those concerning the prudence and reasonableness of the costs incurred by the utility, in the hearing as it would apply in a hearing to review a filing for a general increase in rates under Article IX of this Act. The Commission shall not, however, have the authority in a proceeding under this subsection (d) to consider or order any changes to the structure or protocols of the performance-based formula rate approved pursuant to subsection (c) of this Section. In a proceeding under this subsection (d), the Commission shall enter its order no later than the earlier of 240 days after the utility's filing of its annual update of cost inputs to the performance-based formula rate or December 31. The Commission's determinations of the prudence and reasonableness of the costs incurred for the applicable calendar year shall be final upon entry of the Commission's order and shall not be subject to reopening, reexamination, or collateral attack in any other Commission proceeding, case, docket, order, rule or regulation, provided, however, that nothing in this subsection (d) shall prohibit a party from petitioning the Commission to rehear or appeal to the courts the order pursuant to the provisions of this Act.
    In the event the Commission does not, either upon complaint or its own initiative, enter upon a hearing within 45 days after the utility files the annual update of cost inputs to its performance-based formula rate, then the costs incurred for the applicable calendar year shall be deemed prudent and reasonable, and the filed charges shall not be subject to reopening, reexamination, or collateral attack in any other proceeding, case, docket, order, rule, or regulation.
    A participating utility's first filing of the updated cost inputs, and any Commission investigation of such inputs pursuant to this subsection (d) shall proceed notwithstanding the fact that the Commission's investigation under subsection (c) of this Section is still pending and notwithstanding any other law, order, rule, or Commission practice to the contrary.
    (e) Nothing in subsections (c) or (d) of this Section shall prohibit the Commission from investigating, or a participating utility from filing, revenue-neutral tariff changes related to rate design of a performance-based formula rate that has been placed into effect for the utility. Following approval of a participating utility's performance-based formula rate tariff pursuant to subsection (c) of this Section, the utility shall make a filing with the Commission within one year after the effective date of the performance-based formula rate tariff that proposes changes to the tariff to incorporate the findings of any final rate design orders of the Commission applicable to the participating utility and entered subsequent to the Commission's approval of the tariff. The Commission shall, after notice and hearing, enter its order approving, or approving with modification, the proposed changes to the performance-based formula rate tariff within 240 days after the utility's filing. Following such approval, the utility shall make a filing with the Commission during each subsequent 3-year period that either proposes revenue-neutral tariff changes or re-files the existing tariffs without change, which shall present the Commission with an opportunity to suspend the tariffs and consider revenue-neutral tariff changes related to rate design.
    (f) Within 30 days after the filing of a tariff pursuant to subsection (c) of this Section, each participating utility shall develop and file with the Commission multi-year metrics designed to achieve, ratably (i.e., in equal segments) over a 10-year period, improvement over baseline performance values as follows:
        (1) Twenty percent improvement in the System Average
    
Interruption Frequency Index, using a baseline of the average of the data from 2001 through 2010.
        (2) Fifteen percent improvement in the system
    
Customer Average Interruption Duration Index, using a baseline of the average of the data from 2001 through 2010.
        (3) For a participating utility other than a
    
combination utility, 20% improvement in the System Average Interruption Frequency Index for its Southern Region, using a baseline of the average of the data from 2001 through 2010. For purposes of this paragraph (3), Southern Region shall have the meaning set forth in the participating utility's most recent report filed pursuant to Section 16-125 of this Act.
        (3.5) For a participating utility other than a
    
combination utility, 20% improvement in the System Average Interruption Frequency Index for its Northeastern Region, using a baseline of the average of the data from 2001 through 2010. For purposes of this paragraph (3.5), Northeastern Region shall have the meaning set forth in the participating utility's most recent report filed pursuant to Section 16-125 of this Act.
        (4) Seventy-five percent improvement in the total
    
number of customers who exceed the service reliability targets as set forth in subparagraphs (A) through (C) of paragraph (4) of subsection (b) of 83 Ill. Admin. Code Part 411.140 as of May 1, 2011, using 2010 as the baseline year.
        (5) Reduction in issuance of estimated electric
    
bills: 90% improvement for a participating utility other than a combination utility, and 56% improvement for a participating utility that is a combination utility, using a baseline of the average number of estimated bills for the years 2008 through 2010.
        (6) Consumption on inactive meters: 90% improvement
    
for a participating utility other than a combination utility, and 56% improvement for a participating utility that is a combination utility, using a baseline of the average unbilled kilowatthours for the years 2009 and 2010.
        (7) Unaccounted for energy: 50% improvement for a
    
participating utility other than a combination utility using a baseline of the non-technical line loss unaccounted for energy kilowatthours for the year 2009.
        (8) Uncollectible expense: reduce uncollectible
    
expense by at least $30,000,000 for a participating utility other than a combination utility and by at least $3,500,000 for a participating utility that is a combination utility, using a baseline of the average uncollectible expense for the years 2008 through 2010.
        (9) Opportunities for minority-owned and female-owned
    
business enterprises: design a performance metric regarding the creation of opportunities for minority-owned and female-owned business enterprises consistent with State and federal law using a base performance value of the percentage of the participating utility's capital expenditures that were paid to minority-owned and female-owned business enterprises in 2010.
    The definitions set forth in 83 Ill. Admin. Code Part 411.20 as of May 1, 2011 shall be used for purposes of calculating performance under paragraphs (1) through (3.5) of this subsection (f), provided, however, that the participating utility may exclude up to 9 extreme weather event days from such calculation for each year, and provided further that the participating utility shall exclude 9 extreme weather event days when calculating each year of the baseline period to the extent that there are 9 such days in a given year of the baseline period. For purposes of this Section, an extreme weather event day is a 24-hour calendar day (beginning at 12:00 a.m. and ending at 11:59 p.m.) during which any weather event (e.g., storm, tornado) caused interruptions for 10,000 or more of the participating utility's customers for 3 hours or more. If there are more than 9 extreme weather event days in a year, then the utility may choose no more than 9 extreme weather event days to exclude, provided that the same extreme weather event days are excluded from each of the calculations performed under paragraphs (1) through (3.5) of this subsection (f).
    The metrics shall include incremental performance goals for each year of the 10-year period, which shall be designed to demonstrate that the utility is on track to achieve the performance goal in each category at the end of the 10-year period. The utility shall elect when the 10-year period shall commence for the metrics set forth in subparagraphs (1) through (4) and (9) of this subsection (f), provided that it begins no later than 14 months following the date on which the utility begins investing pursuant to subsection (b) of this Section, and when the 10-year period shall commence for the metrics set forth in subparagraphs (5) through (8) of this subsection (f), provided that it begins no later than 14 months following the date on which the Commission enters its order approving the utility's Advanced Metering Infrastructure Deployment Plan pursuant to subsection (c) of Section 16-108.6 of this Act.
    The metrics and performance goals set forth in subparagraphs (5) through (8) of this subsection (f) are based on the assumptions that the participating utility may fully implement the technology described in subsection (b) of this Section, including utilizing the full functionality of such technology and that there is no requirement for personal on-site notification. If the utility is unable to meet the metrics and performance goals set forth in subparagraphs (5) through (8) of this subsection (f) for such reasons, and the Commission so finds after notice and hearing, then the utility shall be excused from compliance, but only to the limited extent achievement of the affected metrics and performance goals was hindered by the less than full implementation.
    (f-5) The financial penalties applicable to the metrics described in subparagraphs (1) through (8) of subsection (f) of this Section, as applicable, shall be applied through an adjustment to the participating utility's return on equity of no more than a total of 30 basis points in each of the first 3 years, of no more than a total of 34 basis points in each of the 3 years thereafter, and of no more than a total of 38 basis points in each of the 4 years thereafter, as follows:
        (1) With respect to each of the incremental annual
    
performance goals established pursuant to paragraph (1) of subsection (f) of this Section,
            (A) for each year that a participating utility
        
other than a combination utility does not achieve the annual goal, the participating utility's return on equity shall be reduced as follows: during years 1 through 3, by 5 basis points; during years 4 through 6, by 6 basis points; and during years 7 through 10, by 7 basis points; and
            (B) for each year that a participating utility
        
that is a combination utility does not achieve the annual goal, the participating utility's return on equity shall be reduced as follows: during years 1 through 3, by 10 basis points; during years 4 through 6, by 12 basis points; and during years 7 through 10, by 14 basis points.
        (2) With respect to each of the incremental annual
    
performance goals established pursuant to paragraph (2) of subsection (f) of this Section, for each year that the participating utility does not achieve each such goal, the participating utility's return on equity shall be reduced as follows: during years 1 through 3, by 5 basis points; during years 4 through 6, by 6 basis points; and during years 7 through 10, by 7 basis points.
        (3) With respect to each of the incremental annual
    
performance goals established pursuant to paragraphs (3) and (3.5) of subsection (f) of this Section, for each year that a participating utility other than a combination utility does not achieve both such goals, the participating utility's return on equity shall be reduced as follows: during years 1 through 3, by 5 basis points; during years 4 through 6, by 6 basis points; and during years 7 through 10, by 7 basis points.
        (4) With respect to each of the incremental annual
    
performance goals established pursuant to paragraph (4) of subsection (f) of this Section, for each year that the participating utility does not achieve each such goal, the participating utility's return on equity shall be reduced as follows: during years 1 through 3, by 5 basis points; during years 4 through 6, by 6 basis points; and during years 7 through 10, by 7 basis points.
        (5) With respect to each of the incremental annual
    
performance goals established pursuant to subparagraph (5) of subsection (f) of this Section, for each year that the participating utility does not achieve at least 95% of each such goal, the participating utility's return on equity shall be reduced by 5 basis points for each such unachieved goal.
        (6) With respect to each of the incremental annual
    
performance goals established pursuant to paragraphs (6), (7), and (8) of subsection (f) of this Section, as applicable, which together measure non-operational customer savings and benefits relating to the implementation of the Advanced Metering Infrastructure Deployment Plan, as defined in Section 16-108.6 of this Act, the performance under each such goal shall be calculated in terms of the percentage of the goal achieved. The percentage of goal achieved for each of the goals shall be aggregated, and an average percentage value calculated, for each year of the 10-year period. If the utility does not achieve an average percentage value in a given year of at least 95%, the participating utility's return on equity shall be reduced by 5 basis points.
    The financial penalties shall be applied as described in this subsection (f-5) for the 12-month period in which the deficiency occurred through a separate tariff mechanism, which shall be filed by the utility together with its metrics. In the event the formula rate tariff established pursuant to subsection (c) of this Section terminates, the utility's obligations under subsection (f) of this Section and this subsection (f-5) shall also terminate, provided, however, that the tariff mechanism established pursuant to subsection (f) of this Section and this subsection (f-5) shall remain in effect until any penalties due and owing at the time of such termination are applied.
    The Commission shall, after notice and hearing, enter an order within 120 days after the metrics are filed approving, or approving with modification, a participating utility's tariff or mechanism to satisfy the metrics set forth in subsection (f) of this Section. On June 1 of each subsequent year, each participating utility shall file a report with the Commission that includes, among other things, a description of how the participating utility performed under each metric and an identification of any extraordinary events that adversely impacted the utility's performance. Whenever a participating utility does not satisfy the metrics required pursuant to subsection (f) of this Section, the Commission shall, after notice and hearing, enter an order approving financial penalties in accordance with this subsection (f-5). The Commission-approved financial penalties shall be applied beginning with the next rate year. Nothing in this Section shall authorize the Commission to reduce or otherwise obviate the imposition of financial penalties for failing to achieve one or more of the metrics established pursuant to subparagraph (1) through (4) of subsection (f) of this Section.
    (g) On or before July 31, 2014, each participating utility shall file a report with the Commission that sets forth the average annual increase in the average amount paid per kilowatthour for residential eligible retail customers, exclusive of the effects of energy efficiency programs, comparing the 12-month period ending May 31, 2012; the 12-month period ending May 31, 2013; and the 12-month period ending May 31, 2014. For a participating utility that is a combination utility with more than one rate zone, the weighted average aggregate increase shall be provided. The report shall be filed together with a statement from an independent auditor attesting to the accuracy of the report. The cost of the independent auditor shall be borne by the participating utility and shall not be a recoverable expense. "The average amount paid per kilowatthour" shall be based on the participating utility's tariffed rates actually in effect and shall not be calculated using any hypothetical rate or adjustments to actual charges (other than as specified for energy efficiency) as an input.
    In the event that the average annual increase exceeds 2.5% as calculated pursuant to this subsection (g), then Sections 16-108.5, 16-108.6, 16-108.7, and 16-108.8 of this Act, other than this subsection, shall be inoperative as they relate to the utility and its service area as of the date of the report due to be submitted pursuant to this subsection and the utility shall no longer be eligible to annually update the performance-based formula rate tariff pursuant to subsection (d) of this Section. In such event, the then current rates shall remain in effect until such time as new rates are set pursuant to Article IX of this Act, subject to retroactive adjustment, with interest, to reconcile rates charged with actual costs, and the participating utility's voluntary commitments and obligations under subsection (b) of this Section shall immediately terminate, except for the utility's obligation to pay an amount already owed to the fund for training grants pursuant to a Commission order issued under subsection (b) of this Section.
    In the event that the average annual increase is 2.5% or less as calculated pursuant to this subsection (g), then the performance-based formula rate shall remain in effect as set forth in this Section.
    For purposes of this Section, the amount per kilowatthour means the total amount paid for electric service expressed on a per kilowatthour basis, and the total amount paid for electric service includes without limitation amounts paid for supply, transmission, distribution, surcharges, and add-on taxes exclusive of any increases in taxes or new taxes imposed after the effective date of this amendatory Act of the 97th General Assembly. For purposes of this Section, "eligible retail customers" shall have the meaning set forth in Section 16-111.5 of this Act.
    The fact that this Section becomes inoperative as set forth in this subsection shall not be construed to mean that the Commission may reexamine or otherwise reopen prudence or reasonableness determinations already made.
    (h) Sections 16-108.5, 16-108.6, 16-108.7, and 16-108.8 of this Act, other than this subsection, are inoperative after December 31, 2017 for every participating utility, after which time a participating utility shall no longer be eligible to annually update the performance-based formula rate tariff pursuant to subsection (d) of this Section. At such time, the then current rates shall remain in effect until such time as new rates are set pursuant to Article IX of this Act, subject to retroactive adjustment, with interest, to reconcile rates charged with actual costs.
    By December 31, 2017, the Commission shall prepare and file with the General Assembly a report on the infrastructure program and the performance-based formula rate. The report shall include the change in the average amount per kilowatthour paid by residential customers between June 1, 2011 and May 31, 2017. If the change in the total average rate paid exceeds 2.5% compounded annually, the Commission shall include in the report an analysis that shows the portion of the change due to the delivery services component and the portion of the change due to the supply component of the rate. The report shall include separate sections for each participating utility.
    In the event Sections 16-108.5, 16-108.6, 16-108.7, and 16-108.8 of this Act do not become inoperative after December 31, 2017, then these Sections are inoperative after December 31, 2022 for every participating utility, after which time a participating utility shall no longer be eligible to annually update the performance-based formula rate tariff pursuant to subsection (d) of this Section. At such time, the then current rates shall remain in effect until such time as new rates are set pursuant to Article IX of this Act, subject to retroactive adjustment, with interest, to reconcile rates charged with actual costs.
    The fact that this Section becomes inoperative as set forth in this subsection shall not be construed to mean that the Commission may reexamine or otherwise reopen prudence or reasonableness determinations already made.
    (i) While a participating utility may use, develop, and maintain broadband systems and the delivery of broadband services, voice-over-internet-protocol services, telecommunications services, and cable and video programming services for use in providing delivery services and Smart Grid functionality or application to its retail customers, including, but not limited to, the installation, implementation and maintenance of Smart Grid electric system upgrades as defined in Section 16-108.6 of this Act, a participating utility is prohibited from offering to its retail customers broadband services or the delivery of broadband services, voice-over-internet-protocol services, telecommunications services, or cable or video programming services, unless they are part of a service directly related to delivery services or Smart Grid functionality or applications as defined in Section 16-108.6 of this Act, and from recovering the costs of such offerings from retail customers.
    (j) Nothing in this Section is intended to legislatively overturn the opinion issued in Commonwealth Edison Co. v. Ill. Commerce Comm'n, Nos. 2-08-0959, 2-08-1037, 2-08-1137, 1-08-3008, 1-08-3030, 1-08-3054, 1-08-3313 cons. (Ill. App. Ct. 2d Dist. Sept. 30, 2010). This amendatory Act of the 97th General Assembly shall not be construed as creating a contract between the General Assembly and the participating utility, and shall not establish a property right in the participating utility.
    (k) The changes made in subsections (c) and (d) of this Section by this amendatory Act of the 98th General Assembly are intended to be a restatement and clarification of existing law, and intended to give binding effect to the provisions of House Resolution 1157 adopted by the House of Representatives of the 97th General Assembly and Senate Resolution 821 adopted by the Senate of the 97th General Assembly that are reflected in paragraph (3) of this subsection. In addition, this amendatory Act of the 98th General Assembly preempts and supersedes any final Commission orders entered in Docket Nos. 11-0721, 12-0001, 12-0293, and 12-0321 to the extent inconsistent with the amendatory language added to subsections (c) and (d).
        (1) No earlier than 5 business days after the
    
effective date of this amendatory Act of the 98th General Assembly, each participating utility shall file any tariff changes necessary to implement the amendatory language set forth in subsections (c) and (d) of this Section by this amendatory Act of the 98th General Assembly and a revised revenue requirement under the participating utility's performance-based formula rate. The Commission shall enter a final order approving such tariff changes and revised revenue requirement within 21 days after the participating utility's filing.
        (2) Notwithstanding anything that may be to the
    
contrary, a participating utility may file a tariff to retroactively recover its previously unrecovered actual costs of delivery service that are no longer subject to recovery through a reconciliation adjustment under subsection (d) of this Section. This retroactive recovery shall include any derivative adjustments resulting from the changes to subsections (c) and (d) of this Section by this amendatory Act of the 98th General Assembly. Such tariff shall allow the utility to assess, on current customer bills over a period of 12 monthly billing periods, a charge or credit related to those unrecovered costs with interest at the utility's weighted average cost of capital during the period in which those costs were unrecovered. A participating utility may file a tariff that implements a retroactive charge or credit as described in this paragraph for amounts not otherwise included in the tariff filing provided for in paragraph (1) of this subsection (k). The Commission shall enter a final order approving such tariff within 21 days after the participating utility's filing.
        (3) The tariff changes described in paragraphs (1)
    
and (2) of this subsection (k) shall relate only to, and be consistent with, the following provisions of this amendatory Act of the 98th General Assembly: paragraph (2) of subsection (c) regarding year-end capital structure, subparagraph (D) of paragraph (4) of subsection (c) regarding pension assets, and subsection (d) regarding the reconciliation components related to year-end rate base and interest calculated at a rate equal to the utility's weighted average cost of capital.
        (4) Nothing in this subsection is intended to effect
    
a dismissal of or otherwise affect an appeal from any final Commission orders entered in Docket Nos. 11-0721, 12-0001, 12-0293, and 12-0321 other than to the extent of the amendatory language contained in subsections (c) and (d) of this amendatory Act of the 98th General Assembly.
    (l) Each participating utility shall be deemed to have been in full compliance with all requirements of subsection (b) of this Section, subsection (c) of this Section, Section 16-108.6 of this Act, and all Commission orders entered pursuant to Sections 16-108.5 and 16-108.6 of this Act, up to and including the effective date of this amendatory Act of the 98th General Assembly. The Commission shall not undertake any investigation of such compliance and no penalty shall be assessed or adverse action taken against a participating utility for noncompliance with Commission orders associated with subsection (b) of this Section, subsection (c) of this Section, and Section 16-108.6 of this Act prior to such date. Each participating utility other than a combination utility shall be permitted, without penalty, a period of 12 months after such effective date to take actions required to ensure its infrastructure investment program is in compliance with subsection (b) of this Section and with Section 16-108.6 of this Act. Provided further:
        (1) if this amendatory Act of the 98th General
    
Assembly takes effect on or before June 15, 2013, the following subparagraphs shall apply to a participating utility other than a combination utility:
            (A) if the Commission has initiated a proceeding
        
pursuant to subsection (e) of Section 16-108.6 of this Act that is pending as of the effective date of this amendatory Act of the 98th General Assembly, then the order entered in such proceeding shall, after notice and hearing, accelerate the commencement of the meter deployment schedule approved in the final Commission order on rehearing entered in Docket No. 12-0298;
            (B) if the Commission has entered an order
        
pursuant to subsection (e) of Section 16-108.6 of this Act prior to the effective date of this amendatory Act of the 98th General Assembly that does not accelerate the commencement of the meter deployment schedule approved in the final Commission order on rehearing entered in Docket No. 12-0298, then the utility shall file with the Commission, within 45 days after such effective date, a plan for accelerating the commencement of the utility's meter deployment schedule approved in the final Commission order on rehearing entered in Docket No. 12-0298; the Commission shall reopen the proceeding in which it entered its order pursuant to subsection (e) of Section 16-108.6 of this Act and shall, after notice and hearing, enter an amendatory order that approves or approves as modified such accelerated plan within 90 days after the utility's filing; or
            (C) if the Commission has not initiated a
        
proceeding pursuant to subsection (e) of Section 16-108.6 of this Act prior to the effective date of this amendatory Act of the 98th General Assembly, then the utility shall file with the Commission, within 45 days after such effective date, a plan for accelerating the commencement of the utility's meter deployment schedule approved in the final Commission order on rehearing entered in Docket No. 12-0298 and the Commission shall, after notice and hearing, approve or approve as modified such plan within 90 days after the utility's filing;
        (2) if this amendatory Act of the 98th General
    
Assembly takes effect after June 15, 2013, then each participating utility other than a combination utility shall file with the Commission, within 45 days after such effective date, a plan for accelerating the commencement of the utility's meter deployment schedule approved in the final Commission order on rehearing entered in Docket No. 12-0298; the Commission shall reopen the most recent proceeding in which it entered an order pursuant to subsection (e) of Section 16-108.6 of this Act and within 90 days after the utility's filing shall, after notice and hearing, enter an amendatory order that approves or approves as modified such accelerated plan, provided that if there was no such prior proceeding the Commission shall open a new proceeding and within 90 days after the utility's filing shall, after notice and hearing, enter an order that approves or approves as modified such accelerated plan.
    Any schedule for meter deployment approved by the Commission pursuant to subparagraphs (1) or (2) of this subsection (l) shall take into consideration procurement times for meters and other equipment and operational issues. Nothing in this amendatory Act of the 98th General Assembly shall shorten or extend the end dates for the 5-year or 10-year periods set forth in subsection (b) of this Section or Section 16-108.6 of this Act. Nothing in this subsection is intended to address whether a participating utility has, or has not, satisfied any or all of the metrics and performance goals established pursuant to subsection (f) of this Section.
    (m) The provisions of this amendatory Act of the 98th General Assembly are severable under Section 1.31 of the Statute on Statutes.
(Source: P.A. 97-616, eff. 10-26-11; 97-646, eff. 12-30-11; 98-15, eff. 5-22-13.)

    (220 ILCS 5/16-108.6)
    Sec. 16-108.6. Provisions relating to Smart Grid Advanced Metering Infrastructure Deployment Plan.
    (a) For purposes of this Section and Sections 16-108.7 and 16-108.8 of this Act:
    "Advanced Metering Infrastructure" or "AMI" means the communications hardware and software and associated system software that enables Smart Grid functions by creating a network between advanced meters and utility business systems and allowing collection and distribution of information to customers and other parties in addition to providing information to the utility itself.
    "Cost-beneficial" means a determination that the benefits of a participating utility's Smart Grid AMI Deployment Plan exceed the costs of the Smart Grid AMI Deployment Plan as initially filed with the Commission or as subsequently modified by the Commission. This standard is met if the present value of the total benefits of the Smart Grid AMI Deployment Plan exceeds the present value of the total costs of the Smart Grid AMI Deployment Plan. The total cost shall include all utility costs reasonably associated with the Smart Grid AMI Deployment Plan. The total benefits shall include the sum of avoided electricity costs, including avoided utility operational costs, avoided consumer power, capacity, and energy costs, and avoided societal costs associated with the production and consumption of electricity, as well as other societal benefits, including the greater integration of renewable and distributed power resources, reductions in the emissions of harmful pollutants and associated avoided health-related costs, other benefits associated with energy efficiency measures, demand-response activities, and the enabling of greater penetration of alternative fuel vehicles.
    "Participating utility" has the meaning set forth in Section 16-108.5 of this Act.
    "Smart Grid" means investments and policies that together promote one or more of the following goals:
        (1) Increased use of digital information and controls

    
technology to improve reliability, security, and efficiency of the electric grid.
        (2) Dynamic optimization of grid operations and
    
resources, with full cyber security.
        (3) Deployment and integration of distributed
    
resources and generation, including renewable resources.
        (4) Development and incorporation of demand-response,
    
demand-side resources, and energy efficiency resources.
        (5) Deployment of "smart" technologies (real-time,
    
automated, interactive technologies that optimize the physical operation of appliances and consumer devices) for metering, communications concerning grid operations and status, and distribution automation.
        (6) Integration of "smart" appliances and consumer
    
devices.
        (7) Deployment and integration of advanced
    
electricity storage and peak-shaving technologies, including plug-in electric and hybrid electric vehicles, thermal-storage air conditioning and renewable energy generation.
        (8) Provision to consumers of timely information and
    
control options.
        (9) Development of open access standards for
    
communication and interoperability of appliances and equipment connected to the electric grid, including the infrastructure serving the grid.
        (10) Identification and lowering of unreasonable or
    
unnecessary barriers to adoption of Smart Grid technologies, practices, services, and business models that support energy efficiency, demand-response, and distributed generation.
    "Smart Grid Advisory Council" means the group of stakeholders formed pursuant to subsection (b) of this Section for the purposes of advising and working with participating utilities on the development and implementation of a Smart Grid Advanced Metering Infrastructure Deployment Plan.
    "Smart Grid electric system upgrades" means any of the following:
        (1) metering devices, sensors, control devices, and
    
other devices integrated with and attached to an electric utility system that are capable of engaging in Smart Grid functions;
        (2) other monitoring and communications devices that
    
enable Smart Grid functions, including, but not limited to, distribution automation;
        (3) software that enables devices or computers to
    
engage in Smart Grid functions;
        (4) associated cyber secure data communication
    
network, including enhancements to cyber-security technologies and measures;
        (5) substation micro-processor relay upgrades;
        (6) devices that allow electric or hybrid-electric
    
vehicles to engage in Smart Grid functions; or
        (7) devices that enable individual consumers to
    
incorporate distributed and micro-generation.
    "Smart Grid electric system upgrades" does not include expenditures for: (1) electricity generation, transmission, or distribution infrastructure or equipment that does not directly relate to or support installing, implementing or enabling Smart Grid functions; (2) physical interconnection of generators or other devices to the grid except those that are directly related to enabling Smart Grid functions; or (3) ongoing or routine operation, billing, customer relations, security, and maintenance.
    "Smart Grid functions" means:
        (1) the ability to develop, store, send, and receive
    
digital information concerning or enabling grid operations, electricity use, costs, prices, time of use, nature of use, storage, or other information relevant to device, grid, or utility operations, to or from or by means of the electric utility system through one or a combination of devices and technologies;
        (2) the ability to develop, store, send, and receive
    
digital information concerning electricity use, costs, prices, time of use, nature of use, storage, or other information relevant to device, grid, or utility operations to or from a computer or other control device;
        (3) the ability to measure or monitor electricity use
    
as a function of time of day, power quality characteristics such as voltage level, current, cycles per second, or source or type of generation and to store, synthesize, or report that information by digital means;
        (4) the ability to sense and localize disruptions or
    
changes in power flows on the grid and communicate such information instantaneously and automatically for purposes of enabling automatic protective responses to sustain reliability and security of grid operations;
        (5) the ability to detect, prevent, communicate with
    
regard to, respond to, or recover from system security threats, including cyber-security threats and terrorism, using digital information, media, and devices;
        (6) the ability of any device or machine to respond
    
to signals, measurements, or communications automatically or in a manner programmed by its owner or operator without independent human intervention;
        (7) the ability to use digital information to operate
    
functionalities on the electric utility grid that were previously electro-mechanical or manual;
        (8) the ability to use digital controls to manage and
    
modify electricity demand, enable congestion management, assist in voltage control, provide operating reserves, and provide frequency regulation; or
        (9) the ability to integrate electric plug-in
    
vehicles, distributed generation, and storage in a safe and cost-effective manner on the electric grid.
    (b) Within 30 days after the effective date of this amendatory Act of the 97th General Assembly, the Smart Grid Advisory Council shall be established, which shall consist of 9 total voting members with each member possessing either technical, business or consumer expertise in Smart Grid issues, 5 of whom shall be appointed by the Governor, one of whom shall be appointed by the Speaker of the House, one of whom shall be appointed by the Minority Leader of the House, one of whom shall be appointed by the President of the Senate, and one of whom shall be appointed by the Minority Leader of the Senate. Of the Governor's 5 appointments: (i) at least one must represent a non-profit membership organization whose mission is to cultivate innovation and technology-based economic development in Illinois by fostering public-private partnerships to develop and execute research and development projects, advocating for funding for research and development initiatives, and collaborating with public and private partners to attract and retain research and development resources and talent in Illinois; (ii) at least one must represent a non-profit public body corporate and politic created by law that has a duty to represent and protect residential utility consumers in Illinois; (iii) at least one must represent a membership organization that represents the interests of individuals and companies that own, operate, manage, and service commercial buildings in a municipality with a population of 1,000,000 or more inhabitants; and (iv) at least one must represent an alternative retail electric supplier that has obtained a certificate of service authority pursuant to Section 16-115 of this Act and that is not an affiliate of a participating utility prior to one year after the effective date of this amendatory Act of the 97th General Assembly.
    The Governor shall designate one of the members of the Council to serve as chairman, and that person shall serve as the chairman at the pleasure of the Governor. The members shall not be compensated for serving on the Smart Grid Advisory Council. The Smart Grid Advisory Council shall have the following duties:
        (1) Serve as an advisor to participating utilities
    
subject to this Section and in the manner described in this Section, and the recommendations provided by the Council, although non-binding, shall be considered by the utilities.
        (2) Serve as trustees of the trust or foundation
    
established pursuant to Section 16-108.7 of this Act with the duties enumerated thereunder.
    (c) After consultation with the Smart Grid Advisory Council, each participating utility shall file a Smart Grid Advanced Metering Infrastructure Deployment Plan ("AMI Plan") with the Commission within 180 days after the effective date of this amendatory Act of the 97th General Assembly or by November 1, 2011, whichever is later, or in the case of a combination utility as defined in Section 16-108.5, by April 1, 2012, provided that a participating utility shall not file its plan until the evaluation report on the Pilot Program described in this subsection (c) is issued. The AMI Plan shall provide for investment over a 10-year period that is sufficient to implement the AMI Plan across its entire service territory in a manner that is consistent with subsection (b) of Section 16-108.5 of this Act. The AMI Plan shall contain:
        (1) the participating utility's Smart Grid AMI vision
    
statement that is consistent with the goal of developing a cost-beneficial Smart Grid;
        (2) a statement of Smart Grid AMI strategy that
    
includes a description of how the utility evaluates and prioritizes technology choices to create customer value, including a plan to enhance and enable customers' ability to take advantage of Smart Grid functions beginning at the time an account has billed successfully on the AMI network;
        (3) a deployment schedule and plan that includes
    
deployment of AMI to all customers for a participating utility other than a combination utility, and to 62% of all customers for a participating utility that is a combination utility;
        (4) annual milestones and metrics for the purposes of
    
measuring the success of the AMI Plan in enabling Smart Grid functions; and enhancing consumer benefits from Smart Grid AMI; and
        (5) a plan for the consumer education to be
    
implemented by the participating utility.
    The AMI Plan shall be fully consistent with the standards of the National Institute of Standard and Technology (NIST) for Smart Grid interoperability that are in effect at the time the participating utility files its AMI Plan, shall include open standards and internet protocol to the maximum extent possible consistent with cyber security, and shall maximize, to the extent possible, a flexible smart meter platform that can accept remote device upgrades and contain sufficient internal memory capacity for additional storage capabilities, functions and services without the need for physical access to the meter.
    The AMI Plan shall secure the privacy of personal information and establish the right of consumers to consent to the disclosure of personal energy information to third parties through electronic, web-based, and other means in accordance with State and federal law and regulations regarding consumer privacy and protection of consumer data.
    After notice and hearing, the Commission shall, within 60 days of the filing of an AMI Plan, issue its order approving, or approving with modification, the AMI Plan if the Commission finds that the AMI Plan contains the information required in paragraphs (1) through (5) of this subsection (c) and further finds that the implementation of the AMI Plan will be cost-beneficial consistent with the principles established through the Illinois Smart Grid Collaborative, giving weight to the results of any Commission-approved pilot designed to examine the benefits and costs of AMI deployment. A participating utility's decision to invest pursuant to an AMI Plan approved by the Commission shall not be subject to prudence reviews in subsequent Commission proceedings. Nothing in this subsection (c) is intended to limit the Commission's ability to review the reasonableness of the costs incurred under the AMI Plan. A participating utility shall be allowed to recover the reasonable costs it incurs in implementing a Commission-approved AMI Plan, including the costs of retired meters, and may recover such costs through its tariffs, including the performance-based formula rate tariff approved pursuant to subsection (c) of Section 16-108.5 of this Act.
    (d) The AMI Plan shall secure the privacy of the customer's personal information. "Personal information" for this purpose consists of the customer's name, address, telephone number, and other personally identifying information, as well as information about the customer's electric usage. Electric utilities, their contractors or agents, and any third party who comes into possession of such personal information by virtue of working on Smart Grid technology shall not disclose such personal information to be used in mailing lists or to be used for other commercial purposes not reasonably related to the conduct of the utility's business. Electric utilities shall comply with the consumer privacy requirements of the Personal Information Protection Act. In the event a participating utility receives revenues from the sale of information obtained through Smart Grid technology that is not personal information, the participating utility shall use such revenues to offset the revenue requirement.
    (e) On April 1 of each year beginning in 2013 and after consultation with the Smart Grid Advisory Council, each participating utility shall submit a report regarding the progress it has made toward completing implementation of its AMI Plan. This report shall:
        (1) describe the AMI investments made during the
    
prior 12 months and the AMI investments planned to be made in the following 12 months;
        (2) provide sufficient detail to determine the
    
utility's progress in meeting the metrics and milestones identified by the utility in its AMI Plan; and
        (3) identify any updates to the AMI Plan.
    Within 21 days after the utility files its annual report, the Commission shall have authority, either upon complaint or its own initiative, but with reasonable notice, to enter upon an investigation regarding the utility's progress in implementing the AMI Plan as described in paragraph (1) of this subsection (e). If the Commission finds, after notice and hearing, that the participating utility's progress in implementing the AMI Plan is materially deficient for the given plan year, then the Commission shall issue an order requiring the participating utility to devise a corrective action plan, subject to Commission approval and oversight, to bring implementation back on schedule consistent with the AMI Plan. The Commission's order must be entered within 90 days after the utility files its annual report. If the Commission does not initiate an investigation within 21 days after the utility files its annual report, then the filing shall be deemed accepted by the Commission. The utility shall not be required to suspend implementation of its AMI Plan during any Commission investigation.
    The participating utility's annual report regarding AMI Plan year 10 shall contain a statement verifying that the implementation of its AMI Plan is complete, provided, however, that if the utility is subject to a corrective action plan that extends the implementation period beyond 10 years, the utility shall include the verification statement in its final annual report. Following the date of a Commission order approving the final annual report or the date on which the final report is deemed accepted by the Commission, the utility's annual reporting obligations under this subsection (d) shall terminate, provided, however, that the utility shall have a continuing obligation to provide information, upon request, to the Commission and Smart Grid Advisory Council regarding the AMI Plan.
    (f) Each participating utility shall pay a pro rata share, based on number of customers, of $5,000,000 per year to the trust or foundation established pursuant to Section 16-108.7 of this Act for each plan year of the AMI Plan, which shall be used for purposes of providing customer education regarding smart meters and related consumer-facing technologies and services and 70% of which shall be a recoverable expense; provided that other reasonable amounts expended by the utility for such consumer education shall not be subject to the 70% limitation of this subsection.
    (g) Within 60 days after the Commission approves a participating utility's AMI Plan pursuant to subsection (c) of this Section, the participating utility, after consultation with the Smart Grid Advisory Council, shall file a proposed tariff with the Commission that offers an opt-in market-based peak time rebate program to all residential retail customers with smart meters that is designed to provide, in a competitively neutral manner, rebates to those residential retail customers that curtail their use of electricity during specific periods that are identified as peak usage periods. The total amount of rebates shall be the amount of compensation the utility obtains through markets or programs at the applicable regional transmission organization. The utility shall make all reasonable attempts to secure funding for the peak time rebate program through markets or programs at the applicable regional transmission organization. The rules and procedures for consumers to opt-in to the peak time rebate program shall include electronic sign-up, be designed to maximize participation, and be included on the utility's website. The Commission shall monitor the performance of programs established pursuant to this subsection (g) and shall order the termination or modification of a program if it determines that the program is not, after a reasonable period of time for development of at least 4 years, resulting in net benefits to the residential customers of the participating utility.
    (h) If Section 16-108.5 of this Act becomes inoperative with respect to one or more participating utilities as set forth in subsection (g) or (h) of that Section, then Sections 16-108.5, 16-108.6, 16-108.7, and 16-108.8 of this Act shall become inoperative as to each affected utility and its service area on the same date as Section 16-108.5 becomes inoperative.
(Source: P.A. 97-616, eff. 10-26-11; 97-646, eff. 12-30-11.)

    (220 ILCS 5/16-108.7)
    Sec. 16-108.7. Illinois Science and Energy Innovation Trust.
    (a) Within 90 days of the effective date of this amendatory Act of the 97th General Assembly, the members of the Smart Grid Advisory Council established pursuant to Section 16-108.6 of this Act, or a majority of the members thereof, shall cause to be established an Illinois science and energy innovation trust or foundation for the purposes of providing financial and technical support and assistance to entities, public or private, within the State of Illinois including, but not limited to, units of State and local government, educational and research institutions, corporations, and charitable, educational, environmental and community organizations, for programs and projects that support, encourage or utilize innovative technologies or other methods of modernizing the State's electric grid that will benefit the public by promoting economic development in Illinois. Such activities shall be supported through grants, loans, contracts, or other programs designed to assist and further benefit technological advances in the area of electric grid modernization and operation. The trust or foundation shall also be eligible for receipt of other energy and environmental grant opportunities, from public or private sources. The trust or foundation shall not be a governmental entity.
    (b) Funds received by the trust or foundation pursuant to subsection (f) of Section 16-108.6 of this Act shall be used solely for the purpose of providing consumer education regarding smart meters and related consumer-facing technologies and services and the peak time rebate program described in subsection (g) of Section 16-108.6 of this Act. Thirty percent of such funds received from each participating utility shall be used by the trust or foundation for purposes of providing such education to each participating utility's low-income retail customers, including low-income senior citizens.
    The trust or foundation shall use all funds received pursuant to subsection (f) of Section 16-108.6 of this Act in a manner that reflects the unique needs and characteristics of each participating utility's service territory and in proportion to each participating utility's payment.
    (c) Such trust or foundation shall be governed by a declaration of trust or articles of incorporation and bylaws which shall, at a minimum, provide the following:
        (1) There shall initially be 9 trustees of the trust

    
or foundation, which shall consist of the members of the Smart Grid Advisory Council established pursuant to Section 16-108.6 of this Act. Subsequently, the participating utilities shall appoint one trustee and the Clean Energy Trust shall appoint one non-voting trustee who shall provide expertise regarding early stage investment in Smart Grid projects.
        (2) All trustees shall be entitled to reimbursement
    
for reasonable expenses incurred on behalf of the trust in the performance of their duties as trustees. All such reimbursements shall be paid out of the trust.
        (3) Trustees shall be appointed within 60 days after
    
the creation of the trust or foundation and shall serve for a term of 5 years commencing upon the date of their respective appointments, until their respective successors are appointed and qualified.
        (4) A vacancy in the office of trustee shall be
    
filled by the person holding the office responsible for appointing the trustee whose death or resignation creates the vacancy, and a trustee appointed to fill a vacancy shall serve the remainder of the term of the trustee whose resignation or death created the vacancy.
        (5) The trust or foundation shall have an indefinite
    
term and shall terminate at such time as no trust assets remain.
        (6) The allocation and disbursement of funds for the
    
various purposes for which the trust or foundation is established shall be determined by the trustees in accordance with the declaration of trust or the articles of incorporation and bylaws.
        (7) The trust or foundation shall be authorized to
    
employ an executive director and other employees, or contract management of the trust or foundation in its entirety to an outside organization found suitable by the trustees, to enter into leases, contracts and other obligations on behalf of the trust or foundation, and to incur expenses that the trustees deem necessary or appropriate for the fulfillment of the purposes for which the trust or foundation is established, provided, however, that salaries and administrative expenses incurred on behalf of the trust or foundation shall not exceed 3% of the trust's principal value, or $750,000, whichever is greater, in any given year. The trustees shall not be compensated by the trust or foundation.
        (8) The trustees may create and appoint advisory
    
boards or committees to assist them with the administration of the trust or foundation, and to advise and make recommendations to them regarding the contribution and disbursement of the trust or foundation funds.
        (9) All funds dispersed by the trust or foundation
    
for programs and projects to meet the objectives of the trust or foundation as enumerated in this Section shall be subject to a peer-review process as determined by the trustees. This process shall be designed to determine, in an objective and unbiased manner, those programs and projects that best fit the objectives of the trust or foundation. In each fiscal year the trustees shall determine, based solely on the information provided through the peer-review process, a budget for programs and projects for that fiscal year.
        (10) The trustees shall administer a Smart Grid
    
education fund from which it shall make grants to qualified not-for-profit organizations for the purpose of educating customers with regard to smart meters and related consumer-facing technologies and services. In making such grants the trust or foundation shall strongly encourage grantees to coordinate to the extent practicable and consider recommendations from the participating utilities regarding the development and implementation of customer education plans.
        (11) One of the objectives of the trust or foundation
    
is to remain self-funding. In order to meet this objective, the trustees may sign agreements with those entities receiving funding that provide for license fees, royalties, or other payments to the trust or foundation from such entities that receive support for their product development from the trust or foundation. Such payments, however, shall be contingent on the commercialization of such products, services, or technologies enabled by the funding provided by the trust or foundation.
    (d) The trustees shall notify each participating utility as defined in Section 16-108.5 of this Act of the formation of the trust or foundation. Within 90 days after receipt of the notification, each participating utility that is not a combination utility as defined in Section 16-108.5 of this Act shall contribute $15,000,000 to the trust or foundation, and each participating utility that is a combination utility, as defined in Section 16-108.5 of this Act, shall contribute $7,500,000 to the trust or foundation established pursuant to this Section. Such contributions shall not be a recoverable expense.
    (e) If Section 16-108.5 of this Act becomes inoperative with respect to one or more participating utilities as set forth in subsection (g) or (h) of that Section, then Sections 16-108.5, 16-108.6, 16-108.7, and 16-108.8 of this Act shall become inoperative as to each affected utility and its service area on the same date as Section 16-108.5 becomes inoperative.
(Source: P.A. 97-616, eff. 10-26-11; 97-646, eff. 12-30-11.)

    (220 ILCS 5/16-108.8)
    Sec. 16-108.8. Illinois Smart Grid test bed.
    (a) Within 180 days after the effective date of this amendatory Act of the 97th General Assembly, each participating utility, as defined by Section 16-108.5 of this Act, shall create or otherwise designate a Smart Grid test bed, which may be located at one or more places within the utility's system, for the purposes of allowing for the testing of Smart Grid technologies. The objectives of this test bed shall be to:
        (1) provide an open, unbiased opportunity for testing

    
programs, technologies, business models, and other Smart Grid-related activities;
        (2) provide on-grid locations for the testing of
    
potentially innovative Smart Grid-related technologies and services, including but not limited to those funded by the trust or foundation established pursuant to Section 16-108.7 of this Act;
        (3) facilitate testing of business models or services
    
that help integrate Smart Grid-related technologies into the electric grid, especially those business models that may help promote new products and services for retail customers;
        (4) offer opportunities to test and showcase Smart
    
Grid technologies and services, especially those likely to support the economic development goals of the State of Illinois.
    (b) The test bed shall reside in one or more locations on the participating utility's network. Such locations shall be chosen by the utility to maximize the opportunity for real-time and real-world testing of Smart Grid technologies and services taking into account the safety and security of the participating utility's grid and grid operations.
    (c) The participating utility, with input from the Smart Grid Advisory Council established pursuant to Section 16-108.6 of this Act, shall, as part of its filing under subsection (b) of Section 16-108.5, include a plan for the creation, operation, and administration of the test bed. This plan shall address the following:
        (1) how the utility proposes to comply with each of
    
the objectives set forth in subsection (a) of this Section;
        (2) the proposed location or locations of the test
    
bed;
        (3) the process by which the utility will receive,
    
review, and qualify proposals to use the test bed;
        (4) the criteria by which the utility proposes to
    
qualify proposals to use the test bed, including, but not limited to, safety, reliability, security, customer data security, privacy, and economic development considerations;
        (5) the engineering and operations support that the
    
utility will provide to test bed users, including provision of customer data; and
        (6) the estimated costs to establish, administer and
    
promote the availability of the test bed.
    (d) The test bed should be open to all qualified entities wishing to test programs, technologies, business models, and other Smart Grid-related activities, provided that the utility retains control of its grid and operations and may reject any programs, technologies, business models, and other Smart Grid-related activities that threaten the reliability, safety, security, or operations of its network, or that would threaten the security of customer-identifiable data in the judgment of the utility. The number of technologies and entities participating in the test bed at any time may be limited by the utility based on its determination of its ability to maintain a secure, safe, and reliable grid.
    (e) At a minimum, the test bed shall have the ability to receive live signals from PJM Interconnection LLC or other applicable regional transmission organization, the ability to test new applications in a utility scale environment (to include ramp rate regulations for distributed wind and solar resources), critical peak price response, and market-based power dispatch.
    (f) At the end of the fourth year of operation the test bed shall be subject to an independent evaluation to determine if the test bed is meeting the objectives of this Section or is likely to meet the objectives in the future. The evaluation shall include the performance of the utility as test bed operator. Subject to the findings, the utility and the trust or foundation established pursuant to Section 16-108.7 of this Act may choose to continue operating the test bed.
    (g) The utility shall be entitled to recover all prudently incurred and reasonable costs associated with evaluation of proposals, engineering, construction, operation, and administration of the test bed through the performance-based formula rate tariff established pursuant to Section 16-108.5 of this Act.
    (h) The utility is authorized to charge fees to users of the test bed that shall recover the costs associated with the incremental costs to the utility associated with administration of the test bed, provided, however, that any such fees collected by the utility shall be used to offset the costs to be recovered pursuant to subsection (g) of this Section.
    (i) On a quarterly basis, the utility shall provide the trust or foundation established pursuant to Section 16-108.7 of this Act with a report summarizing test bed activities, customers, discoveries, and other information as shall be mutually deemed relevant.
    (j) To the extent practicable, the utility and trust or foundation established pursuant to Section 16-108.7 of this Act shall jointly pursue resources that enhance the capabilities and capacity of the test bed.
    (k) If Section 16-108.5 of this Act becomes inoperative with respect to one or more participating utilities as set forth in subsection (g) or (h) of that Section, then Sections 16-108.5, 16-108.6, 16-108.7, and 16-108.8 of this Act shall become inoperative as to each affected utility and its service area on the same date as Section 16-108.5 become inoperative.
(Source: P.A. 97-616, eff. 10-26-11.)

    (220 ILCS 5/16-109)
    Sec. 16-109. Unbundling of delivery services; Commission review. The General Assembly finds that the offering of delivery services will, and is intended to, facilitate the development of competition for generation services, and that competition may develop for other services currently offered on a tariffed basis by the electric utility. The Commission shall open a proceeding to investigate the need for and desirability of different or additional unbundling of delivery services for some or all electric utilities 3 years from the date that a tariff for delivery services is first approved or allowed into effect pursuant to this Section. The Commission shall open an additional proceeding to again investigate the need for and desirability of different or additional unbundling of delivery services for some or all electric utilities, 3 years after the entry of its final order in the first investigation proceeding. The Commission shall issue its final order in each investigation proceeding no later than 6 months after the proceeding is initiated. In each such proceeding the Commission shall consider, at a minimum, the effect of additional unbundling on (i) the objective of just and reasonable rates, (ii) electric utility employees, and (iii) the development of competitive markets for electric energy services in Illinois. Specific changes to the delivery services tariffs of individual electric utilities to implement findings and directives stated in an order in an investigation proceeding initiated under this Section shall be addressed through individual electric utility tariff filings. The Commission may also, in accordance with Section 16-108, upon complaint or upon its own initiative without complaint, upon reasonable notice, enter upon a hearing concerning the need and desirability of requiring additional or other unbundling of delivery services offered by electric utilities.
(Source: P.A. 90-561, eff. 12-16-97.)

    (220 ILCS 5/16-109A)
    Sec. 16-109A. Unbundling of prices for tariffed services; Commission investigation. In addition to the unbundling authorized under Sections 16-108 and 16-109, the Commission shall have the authority to investigate the need for, and to require, the restructuring or unbundling of prices for tariffed services, other than delivery services, offered by an electric utility; provided, however, that the Commission shall not enter an order requiring the restructuring or unbundling of prices for any such tariffed services for a customer class of an electric utility prior to the date that the class first becomes eligible for delivery services pursuant to Section 16-104.
(Source: P.A. 90-561, eff. 12-16-97.)

    (220 ILCS 5/16-110)
    Sec. 16-110. Delivery services customer power purchase options.
    (a) Each electric utility shall offer a tariffed service or services in accordance with the terms and conditions set forth in this Section pursuant to which its non-residential delivery services customers may purchase from the electric utility an amount of electric power and energy that is equal to or less than the amounts that are delivered by such electric utility.
    (b) Except as provided in subsection (o) of Section 16-112, a non-residential delivery services customer that is paying transition charges to the electric utility shall be permitted to purchase electric power and energy from the electric utility at a price or prices equal to the sum of (i) the market values that are determined for the electric utility in accordance with Section 16-112 and used by the electric utility to calculate the customer's transition charges and (ii) a fee that compensates the electric utility for any administrative costs it incurs in arranging to supply such electric power and energy. The electric utility may require that the customer purchase such electric power and energy for periods of not less than one year and may also require that the customer give up to 30 days notice for a purchase of one year's duration, and 90 days notice for a purchase of more than one year's duration. A non-residential delivery service customer exercising the option described in this subsection may sell or assign its interests in the electric power or energy that the customer has purchased. In the case of any such assignment or sale by any non-residential delivery service customer to an alternative retail electric supplier that is serving such customer and has been certified pursuant to Section 16-115, an electric utility serving more than 500,000 customers shall provide such power and energy at the same market value as set forth in clause (i) of this subsection, together with the fee charged under clause (ii) of this subsection, less any costs included in such market value or fee with respect to retail marketing activities, provided, however, that in no event shall an electric utility be required after June 1, 2002 to provide power and energy at this market value plus fee that excludes marketing costs for any such assignment or sale by a non-residential customer to an alternative retail electric supplier. At least twice per year, each electric utility shall notify its small commercial retail customers, through bill inserts and other similar means, of their option to obtain electric power and energy through purchases at market value pursuant to this subsection.
    (c) After the transition charge period applicable to a non-residential delivery services customer, and until the provision of electric power and energy is declared competitive for the customer group to which the customer belongs, a non-residential delivery services customer that paid any transition charges it was legally obligated to pay to an electric utility shall be permitted to purchase electric power and energy from the electric utility for contract periods of one year at a price or prices equal to the sum of (i) the market value determined for that customer's class pursuant to Section 16-112 and (ii) to the extent it is not included in such market value, a fee to compensate the electric utility for the service of arranging the supply or purchase of such electric power and energy. The electric utility may require that a delivery services customer give the following notice for such a purchase: (i) for a small commercial retail customer, not more than 30 days; (ii) for a nonresidential customer which is not a small commercial retail customer but which has maximum electrical demand of less than 500 kilowatts, not more than 6 months; (iii) for a nonresidential customer with maximum electrical demand of 500 kilowatts or more but less than one megawatt, not more than 9 months; and (iv) for a nonresidential customer with maximum electrical demand of one megawatt or more, not more than one year. At least twice per year, each electric utility shall notify its small commercial retail customers, through bill inserts or other similar means, of their option to obtain electric power and energy through purchases at market value pursuant to this subsection.
    (d) After the transition charge period applicable to a non-residential delivery services customer, and until the provision of electric power and energy is declared competitive for the customer group to which the customer belongs, a non-residential delivery services customer, other than a small commercial retail customer, that paid any transition charges it was legally obligated to pay to an electric utility shall be permitted to purchase electric power and energy from the electric utility for contract periods of one year at a price or prices equal to (A) the sum of (i) the electric utility's actual cost of procuring such electric power and energy and (ii) a broker's fee to compensate the electric utility for arranging the supply, or, if the utility so elects, (B) the market value of electric power or energy provided by the electric utility determined as set forth in the electric utility's tariff for that customer's class. The electric utility may require that the delivery services customer give up to 30 days notice for such a purchase.
    (e) Each delivery services customer purchasing electric power and energy from the electric utility pursuant to a tariff filed in accordance with this Section shall also pay all of the applicable charges set forth in the electric utility's delivery services tariffs and any other tariffs applicable to the services provided to that customer by the electric utility.
    (f) An electric utility can require a retail customer taking delivery services that formerly generated electric power and energy for its own use and that would not otherwise pay transition charges on a portion of its electric power and energy requirements served on delivery services to pay transition charges on that portion of the customer's electric power and energy requirements as a condition of exercising the delivery services customer power purchase options set forth in this Section.
(Source: P.A. 90-561, eff. 12-16-97; 91-50, eff. 6-30-99.)

    (220 ILCS 5/16-111)
    Sec. 16-111. Rates and restructuring transactions during mandatory transition period; restructuring and other transactions.
    (a) During the mandatory transition period, notwithstanding any provision of Article IX of this Act, and except as provided in subsections (b) and (f) of this Section, the Commission shall not (i) initiate, authorize or order any change by way of increase (other than in connection with a request for rate increase which was filed after September 1, 1997 but prior to October 15, 1997, by an electric utility serving less than 12,500 customers in this State), (ii) initiate or, unless requested by the electric utility, authorize or order any change by way of decrease, restructuring or unbundling (except as provided in Section 16-109A), in the rates of any electric utility that were in effect on October 1, 1996, or (iii) in any order approving any application for a merger pursuant to Section 7-204 that was pending as of May 16, 1997, impose any condition requiring any filing for an increase, decrease, or change in, or other review of, an electric utility's rates or enforce any such condition of any such order; provided, however, that this subsection shall not prohibit the Commission from:
        (1) approving the application of an electric utility

    
to implement an alternative to rate of return regulation or a regulatory mechanism that rewards or penalizes the electric utility through adjustment of rates based on utility performance, pursuant to Section 9-244;
        (2) authorizing an electric utility to eliminate its
    
fuel adjustment clause and adjust its base rate tariffs in accordance with subsection (b), (d), or (f) of Section 9-220 of this Act, to fix its fuel adjustment factor in accordance with subsection (c) of Section 9-220 of this Act, or to eliminate its fuel adjustment clause in accordance with subsection (e) of Section 9-220 of this Act;
        (3) ordering into effect tariffs for delivery
    
services and transition charges in accordance with Sections 16-104 and 16-108, for real-time pricing in accordance with Section 16-107, or the options required by Section 16-110 and subsection (n) of 16-112, allowing a billing experiment in accordance with Section 16-106, or modifying delivery services tariffs in accordance with Section 16-109; or
        (4) ordering or allowing into effect any tariff to
    
recover charges pursuant to Sections 9-201.5, 9-220.1, 9-221, 9-222 (except as provided in Section 9-222.1), 16-108, and 16-114 of this Act, Section 5-5 of the Electricity Infrastructure Maintenance Fee Law, Section 6-5 of the Renewable Energy, Energy Efficiency, and Coal Resources Development Law of 1997, and Section 13 of the Energy Assistance Act.
    After December 31, 2004, the provisions of this subsection (a) shall not apply to an electric utility whose average residential retail rate was less than or equal to 90% of the average residential retail rate for the "Midwest Utilities", as that term is defined in subsection (b) of this Section, based on data reported on Form 1 to the Federal Energy Regulatory Commission for calendar year 1995, and which served between 150,000 and 250,000 retail customers in this State on January 1, 1995 unless the electric utility or its holding company has been acquired by or merged with an affiliate of another electric utility subsequent to January 1, 2002. This exemption shall be limited to this subsection (a) and shall not extend to any other provisions of this Act.
    (b) Notwithstanding the provisions of subsection (a), each Illinois electric utility serving more than 12,500 customers in Illinois shall file tariffs (i) reducing, effective August 1, 1998, each component of its base rates to residential retail customers by 15% from the base rates in effect immediately prior to January 1, 1998 and (ii) if the public utility provides electric service to (A) more than 500,000 customers but less than 1,000,000 customers in this State on January 1, 1999, reducing, effective May 1, 2002, each component of its base rates to residential retail customers by an additional 5% from the base rates in effect immediately prior to January 1, 1998, or (B) at least 1,000,000 customers in this State on January 1, 1999, reducing, effective October 1, 2001, each component of its base rates to residential retail customers by an additional 5% from the base rates in effect immediately prior to January 1, 1998. Provided, however, that (A) if an electric utility's average residential retail rate is less than or equal to the average residential retail rate for a group of Midwest Utilities (consisting of all investor-owned electric utilities with annual system peaks in excess of 1000 megawatts in the States of Illinois, Indiana, Iowa, Kentucky, Michigan, Missouri, Ohio, and Wisconsin), based on data reported on Form 1 to the Federal Energy Regulatory Commission for calendar year 1995, then it shall only be required to file tariffs (i) reducing, effective August 1, 1998, each component of its base rates to residential retail customers by 5% from the base rates in effect immediately prior to January 1, 1998, (ii) reducing, effective October 1, 2000, each component of its base rates to residential retail customers by the lesser of 5% of the base rates in effect immediately prior to January 1, 1998 or the percentage by which the electric utility's average residential retail rate exceeds the average residential retail rate of the Midwest Utilities, based on data reported on Form 1 to the Federal Energy Regulatory Commission for calendar year 1999, and (iii) reducing, effective October 1, 2002, each component of its base rates to residential retail customers by an additional amount equal to the lesser of 5% of the base rates in effect immediately prior to January 1, 1998 or the percentage by which the electric utility's average residential retail rate exceeds the average residential retail rate of the Midwest Utilities, based on data reported on Form 1 to the Federal Energy Regulatory Commission for calendar year 2001; and (B) if the average residential retail rate of an electric utility serving between 150,000 and 250,000 retail customers in this State on January 1, 1995 is less than or equal to 90% of the average residential retail rate for the Midwest Utilities, based on data reported on Form 1 to the Federal Energy Regulatory Commission for calendar year 1995, then it shall only be required to file tariffs (i) reducing, effective August 1, 1998, each component of its base rates to residential retail customers by 2% from the base rates in effect immediately prior to January 1, 1998; (ii) reducing, effective October 1, 2000, each component of its base rates to residential retail customers by 2% from the base rate in effect immediately prior to January 1, 1998; and (iii) reducing, effective October 1, 2002, each component of its base rates to residential retail customers by 1% from the base rates in effect immediately prior to January 1, 1998. Provided, further, that any electric utility for which a decrease in base rates has been or is placed into effect between October 1, 1996 and the dates specified in the preceding sentences of this subsection, other than pursuant to the requirements of this subsection, shall be entitled to reduce the amount of any reduction or reductions in its base rates required by this subsection by the amount of such other decrease. The tariffs required under this subsection shall be filed 45 days in advance of the effective date. Notwithstanding anything to the contrary in Section 9-220 of this Act, no restatement of base rates in conjunction with the elimination of a fuel adjustment clause under that Section shall result in a lesser decrease in base rates than customers would otherwise receive under this subsection had the electric utility's fuel adjustment clause not been eliminated.
    (c) Any utility reducing its base rates by 15% on August 1, 1998 pursuant to subsection (b) shall include the following statement on its bills for residential customers from August 1 through December 31, 1998: "Effective August 1, 1998, your rates have been reduced by 15% by the Electric Service Customer Choice and Rate Relief Law of 1997 passed by the Illinois General Assembly.". Any utility reducing its base rates by 5% on August 1, 1998, pursuant to subsection (b) shall include the following statement on its bills for residential customers from August 1 through December 31, 1998: "Effective August 1, 1998, your rates have been reduced by 5% by the Electric Service Customer Choice and Rate Relief Law of 1997 passed by the Illinois General Assembly.".
    Any utility reducing its base rates by 2% on August 1, 1998 pursuant to subsection (b) shall include the following statement on its bills for residential customers from August 1 through December 31, 1998: "Effective August 1, 1998, your rates have been reduced by 2% by the Electric Service Customer Choice and Rate Relief Law of 1997 passed by the Illinois General Assembly.".
    (d) (Blank.)
    (e) (Blank.)
    (f) During the mandatory transition period, an electric utility may file revised tariffs reducing the price of any tariffed service offered by the electric utility for all customers taking that tariffed service, which shall be effective 7 days after filing.
    (g) Until all classes of tariffed services are declared competitive, an electric utility may, without obtaining any approval of the Commission other than that provided for in this subsection and notwithstanding any other provision of this Act or any rule or regulation of the Commission that would require such approval:
        (1) implement a reorganization, other than a merger
    
of 2 or more public utilities as defined in Section 3-105 or their holding companies;
        (2) retire generating plants from service;
        (3) sell, assign, lease or otherwise transfer assets
    
to an affiliated or unaffiliated entity and as part of such transaction enter into service agreements, power purchase agreements, or other agreements with the transferee; provided, however, that the prices, terms and conditions of any power purchase agreement must be approved or allowed into effect by the Federal Energy Regulatory Commission; or
        (4) use any accelerated cost recovery method
    
including accelerated depreciation, accelerated amortization or other capital recovery methods, or record reductions to the original cost of its assets.
    In order to implement a reorganization, retire generating plants from service, or sell, assign, lease or otherwise transfer assets pursuant to this Section, the electric utility shall comply with subsections (c) and (d) of Section 16-128, if applicable, and subsection (k) of this Section, if applicable, and provide the Commission with at least 30 days notice of the proposed reorganization or transaction, which notice shall include the following information:
         (i) a complete statement of the entries that the
    
electric utility will make on its books and records of account to implement the proposed reorganization or transaction together with a certification from an independent certified public accountant that such entries are in accord with generally accepted accounting principles and, if the Commission has previously approved guidelines for cost allocations between the utility and its affiliates, a certification from the chief accounting officer of the utility that such entries are in accord with those cost allocation guidelines;
         (ii) a description of how the electric utility will
    
use proceeds of any sale, assignment, lease or transfer to retire debt or otherwise reduce or recover the costs of services provided by such electric utility;
         (iii) a list of all federal approvals or approvals
    
required from departments and agencies of this State, other than the Commission, that the electric utility has or will obtain before implementing the reorganization or transaction;
         (iv) an irrevocable commitment by the electric
    
utility that it will not, as a result of the transaction, impose any stranded cost charges that it might otherwise be allowed to charge retail customers under federal law or increase the transition charges that it is otherwise entitled to collect under this Article XVI;
         (v) if the electric utility proposes to sell, assign,
    
lease or otherwise transfer a generating plant that brings the amount of net dependable generating capacity transferred pursuant to this subsection to an amount equal to or greater than 15% of the electric utility's net dependable capacity as of the effective date of this amendatory Act of 1997, and enters into a power purchase agreement with the entity to which such generating plant is sold, assigned, leased, or otherwise transferred, the electric utility also agrees, if its fuel adjustment clause has not already been eliminated, to eliminate its fuel adjustment clause in accordance with subsection (b) of Section 9-220 for a period of time equal to the length of any such power purchase agreement or successor agreement, or until January 1, 2005, whichever is longer; if the capacity of the generating plant so transferred and related power purchase agreement does not result in the elimination of the fuel adjustment clause under this subsection, and the fuel adjustment clause has not already been eliminated, the electric utility shall agree that the costs associated with the transferred plant that are included in the calculation of the rate per kilowatt-hour to be applied pursuant to the electric utility's fuel adjustment clause during such period shall not exceed the per kilowatt-hour cost associated with such generating plant included in the electric utility's fuel adjustment clause during the full calendar year preceding the transfer, with such limit to be adjusted each year thereafter by the Gross Domestic Product Implicit Price Deflator; and
         (vi) in addition, if the electric utility proposes
    
to sell, assign, or lease, (A) either (1) an amount of generating plant that brings the amount of net dependable generating capacity transferred pursuant to this subsection to an amount equal to or greater than 15% of its net dependable capacity on the effective date of this amendatory Act of 1997, or (2) one or more generating plants with a total net dependable capacity of 1100 megawatts, or (B) transmission and distribution facilities that either (1) bring the amount of transmission and distribution facilities transferred pursuant to this subsection to an amount equal to or greater than 15% of the electric utility's total depreciated original cost investment in such facilities, or (2) represent an investment of $25,000,000 in terms of total depreciated original cost, the electric utility shall provide, in addition to the information listed in subparagraphs (i) through (v), the following information: (A) a description of how the electric utility will meet its service obligations under this Act in a safe and reliable manner and (B) the electric utility's projected earned rate of return on common equity for each year from the date of the notice through December 31, 2006 both with and without the proposed transaction. If the Commission has not issued an order initiating a hearing on the proposed transaction within 30 days after the date the electric utility's notice is filed, the transaction shall be deemed approved. The Commission may, after notice and hearing, prohibit the proposed transaction if it makes either or both of the following findings: (1) that the proposed transaction will render the electric utility unable to provide its tariffed services in a safe and reliable manner, or (2) that there is a strong likelihood that consummation of the proposed transaction will result in the electric utility being entitled to request an increase in its base rates. Any hearing initiated by the Commission into the proposed transaction shall be completed, and the Commission's final order approving or prohibiting the proposed transaction shall be entered, within 90 days after the date the electric utility's notice was filed. Provided, however, that a sale, assignment, or lease of transmission facilities to an independent system operator that meets the requirements of Section 16-126 shall not be subject to Commission approval under this Section.
         In any proceeding conducted by the Commission
    
pursuant to this subparagraph (vi), intervention shall be limited to parties with a direct interest in the transaction which is the subject of the hearing and any statutory consumer protection agency as defined in subsection (d) of Section 9-102.1. Notwithstanding the provisions of Section 10-113 of this Act, any application seeking rehearing of an order issued under this subparagraph (vi), whether filed by the electric utility or by an intervening party, shall be filed within 10 days after service of the order.
    The Commission shall not in any subsequent proceeding or otherwise, review such a reorganization or other transaction authorized by this Section, but shall retain the authority to allocate costs as stated in Section 16-111(i). An entity to which an electric utility sells, assigns, leases or transfers assets pursuant to this subsection (g) shall not, as a result of the transactions specified in this subsection (g), be deemed a public utility as defined in Section 3-105. Nothing in this subsection (g) shall change any requirement under the jurisdiction of the Illinois Department of Nuclear Safety including, but not limited to, the payment of fees. Nothing in this subsection (g) shall exempt a utility from obtaining a certificate pursuant to Section 8-406 of this Act for the construction of a new electric generating facility. Nothing in this subsection (g) is intended to exempt the transactions hereunder from the operation of the federal or State antitrust laws. Nothing in this subsection (g) shall require an electric utility to use the procedures specified in this subsection for any of the transactions specified herein. Any other procedure available under this Act may, at the electric utility's election, be used for any such transaction.
    (h) During the mandatory transition period, the Commission shall not establish or use any rates of depreciation, which for purposes of this subsection shall include amortization, for any electric utility other than those established pursuant to subsection (c) of Section 5-104 of this Act or utilized pursuant to subsection (g) of this Section. Provided, however, that in any proceeding to review an electric utility's rates for tariffed services pursuant to Section 9-201, 9-202, 9-250 or 16-111(d) of this Act, the Commission may establish new rates of depreciation for the electric utility in the same manner provided in subsection (d) of Section 5-104 of this Act. An electric utility implementing an accelerated cost recovery method including accelerated depreciation, accelerated amortization or other capital recovery methods, or recording reductions to the original cost of its assets, pursuant to subsection (g) of this Section, shall file a statement with the Commission describing the accelerated cost recovery method to be implemented or the reduction in the original cost of its assets to be recorded. Upon the filing of such statement, the accelerated cost recovery method or the reduction in the original cost of assets shall be deemed to be approved by the Commission as though an order had been entered by the Commission.
    (i) Subsequent to the mandatory transition period, the Commission, in any proceeding to establish rates and charges for tariffed services offered by an electric utility, shall consider only (1) the then current or projected revenues, costs, investments and cost of capital directly or indirectly associated with the provision of such tariffed services; (2) collection of transition charges in accordance with Sections 16-102 and 16-108 of this Act; (3) recovery of any employee transition costs as described in Section 16-128 which the electric utility is continuing to incur, including recovery of any unamortized portion of such costs previously incurred or committed, with such costs to be equitably allocated among bundled services, delivery services, and contracts with alternative retail electric suppliers; and (4) recovery of the costs associated with the electric utility's compliance with decommissioning funding requirements; and shall not consider any other revenues, costs, investments or cost of capital of either the electric utility or of any affiliate of the electric utility that are not associated with the provision of tariffed services. In setting rates for tariffed services, the Commission shall equitably allocate joint and common costs and investments between the electric utility's competitive and tariffed services. In determining the justness and reasonableness of the electric power and energy component of an electric utility's rates for tariffed services subsequent to the mandatory transition period and prior to the time that the provision of such electric power and energy is declared competitive, the Commission shall consider the extent to which the electric utility's tariffed rates for such component for each customer class exceed the market value determined pursuant to Section 16-112, and, if the electric power and energy component of such tariffed rate exceeds the market value by more than 10% for any customer class, may establish such electric power and energy component at a rate equal to the market value plus 10%.
    (j) During the mandatory transition period, an electric utility may elect to transfer to a non-operating income account under the Commission's Uniform System of Accounts either or both of (i) an amount of unamortized investment tax credit that is in addition to the ratable amount which is credited to the electric utility's operating income account for the year in accordance with Section 46(f)(2) of the federal Internal Revenue Code of 1986, as in effect prior to P.L. 101-508, or (ii) "excess tax reserves", as that term is defined in Section 203(e)(2)(A) of the federal Tax Reform Act of 1986, provided that (A) the amount transferred may not exceed the amount of the electric utility's assets that were created pursuant to Statement of Financial Accounting Standards No. 71 which the electric utility has written off during the mandatory transition period, and (B) the transfer shall not be effective until approved by the Internal Revenue Service. An electric utility electing to make such a transfer shall file a statement with the Commission stating the amount and timing of the transfer for which it intends to request approval of the Internal Revenue Service, along with a copy of its proposed request to the Internal Revenue Service for a ruling. The Commission shall issue an order within 14 days after the electric utility's filing approving, subject to receipt of approval from the Internal Revenue Service, the proposed transfer.
    (k) If an electric utility is selling or transferring to a single buyer 5 or more generating plants located in this State with a total net dependable capacity of 5000 megawatts or more pursuant to subsection (g) of this Section and has obtained a sale price or consideration that exceeds 200% of the book value of such plants, the electric utility must provide to the Governor, the President of the Illinois Senate, the Minority Leader of the Illinois Senate, the Speaker of the Illinois House of Representatives, and the Minority Leader of the Illinois House of Representatives no later than 15 days after filing its notice under subsection (g) of this Section or 5 days after the date on which this subsection (k) becomes law, whichever is later, a written commitment in which such electric utility agrees to expend $2 billion outside the corporate limits of any municipality with 1,000,000 or more inhabitants within such electric utility's service area, over a 6-year period beginning with the calendar year in which the notice is filed, on projects, programs, and improvements within its service area relating to transmission and distribution including, without limitation, infrastructure expansion, repair and replacement, capital investments, operations and maintenance, and vegetation management.
    (l) Notwithstanding any other provision of this Act or any rule, regulation, or prior order of the Commission, a public utility providing electric and gas service may do any one or more of the following: transfer assets to, reorganize with, or merge with one or more public utilities under common holding company ownership or control in the manner prescribed in subsection (g) of this Section. No merger transaction costs, such as fees paid to attorneys, investment bankers, and other consultants, incurred in connection with a merger pursuant to this subsection (l) shall be recoverable in any subsequent rate proceeding. Approval of a merger pursuant to this subsection (l) shall not constitute approval of, or otherwise require, rate recovery of other costs incurred in connection with, or to implement the merger, such as the cost of restructuring, combining, or integrating debt, assets, or systems. Such other costs may be recovered only to the extent that the surviving utility can demonstrate that the cost savings produced by such restructuring, combination, or integration exceed the associated costs. Nothing in this subsection (l) shall impair the terms or conditions of employment or the collective bargaining rights of any employees of the utilities that are transferring assets, reorganizing, or merging.
    (m) If an electric utility that on December 31, 2005 provided electric service to at least 100,000 customers in Illinois transfers assets, reorganizes, or merges under this Section, then the same provisions apply that applied during the mandatory transition period under Section 16-128.
(Source: P.A. 95-331, eff. 8-21-07; 95-481, eff. 8-28-07; 95-876, eff. 8-21-08.)

    (220 ILCS 5/16-111.1)
    Sec. 16-111.1. Illinois Clean Energy Community Trust.
    (a) An electric utility which has sold or transferred generating facilities in a transaction to which subsection (k) of Section 16-111 applies is authorized to establish an Illinois clean energy community trust or foundation for the purposes of providing financial support and assistance to entities, public or private, within the State of Illinois including, but not limited to, units of State and local government, educational institutions, corporations, and charitable, educational, environmental and community organizations, for programs and projects that benefit the public by improving energy efficiency, developing renewable energy resources, supporting other energy related projects that improve the State's environmental quality, and supporting projects and programs intended to preserve or enhance the natural habitats and wildlife areas of the State. Provided, however, that the trust or foundation funds shall not be used for the remediation of environmentally impaired property. The trust or foundation may also assist in identifying other energy and environmental grant opportunities.
    (b) Such trust or foundation shall be governed by a declaration of trust or articles of incorporation and bylaws which shall, at a minimum, provide that:
        (1) There shall be 6 voting trustees of the trust or

    
foundation, one of whom shall be appointed by the Governor, one of whom shall be appointed by the President of the Illinois Senate, one of whom shall be appointed by the Minority Leader of the Illinois Senate, one of whom shall be appointed by the Speaker of the Illinois House of Representatives, one of whom shall be appointed by the Minority Leader of the Illinois House of Representatives, and one of whom shall be appointed by the electric utility establishing the trust or foundation, provided that the voting trustee appointed by the utility shall be a representative of a recognized environmental action group selected by the utility. The Governor shall designate one of the 6 voting trustees to serve as chairman of the trust or foundation, who shall serve as chairman of the trust or foundation at the pleasure of the Governor. In addition, there shall be 4 non-voting trustees, one of whom shall be appointed by the Director of Commerce and Economic Opportunity, one of whom shall be appointed by the Director of the Illinois Environmental Protection Agency, one of whom shall be appointed by the Director of Natural Resources, and one of whom shall be appointed by the electric utility establishing the trust or foundation, provided that the non-voting trustee appointed by the utility shall bring financial expertise to the trust or foundation and shall have appropriate credentials therefor.
        (2) All voting trustees and the non-voting trustee
    
with financial expertise shall be entitled to compensation for their services as trustees, provided, however, that no member of the General Assembly and no employee of the electric utility establishing the trust or foundation serving as a voting trustee shall receive any compensation for his or her services as a trustee, and provided further that the compensation to the chairman of the trust shall not exceed $25,000 annually and the compensation to any other trustee shall not exceed $20,000 annually. All trustees shall be entitled to reimbursement for reasonable expenses incurred on behalf of the trust in the performance of their duties as trustees. All such compensation and reimbursements shall be paid out of the trust.
        (3) Trustees shall be appointed within 30 days after
    
the creation of the trust or foundation and shall serve for a term of 5 years commencing upon the date of their respective appointments, until their respective successors are appointed and qualified.
        (4) A vacancy in the office of trustee shall be
    
filled by the person holding the office responsible for appointing the trustee whose death or resignation creates the vacancy, and a trustee appointed to fill a vacancy shall serve the remainder of the term of the trustee whose resignation or death created the vacancy.
        (5) The trust or foundation shall have an indefinite
    
term, and shall terminate at such time as no trust assets remain.
        (6) The trust or foundation shall be funded in the
    
minimum amount of $250,000,000, with the allocation and disbursement of funds for the various purposes for which the trust or foundation is established to be determined by the trustees in accordance with the declaration of trust or the articles of incorporation and bylaws; provided, however, that this amount may be reduced by up to $25,000,000 if, at the time the trust or foundation is funded, a corresponding amount is contributed by the electric utility establishing the trust or foundation to the Board of Trustees of Southern Illinois University for the purpose of funding programs or projects related to clean coal and provided further that $25,000,000 of the amount contributed to the trust or foundation shall be available to fund programs or projects related to clean coal.
        (7) The trust or foundation shall be authorized to
    
employ an executive director and other employees, to enter into leases, contracts and other obligations on behalf of the trust or foundation, and to incur expenses that the trustees deem necessary or appropriate for the fulfillment of the purposes for which the trust or foundation is established, provided, however, that salaries and administrative expenses incurred on behalf of the trust or foundation shall not exceed $500,000 in the first fiscal year after the trust or foundation is established and shall not exceed $1,000,000 in each subsequent fiscal year.
        (8) The trustees may create and appoint advisory
    
boards or committees to assist them with the administration of the trust or foundation, and to advise and make recommendations to them regarding the contribution and disbursement of the trust or foundation funds.
    (c)(1) In addition to the allocation and disbursement of
    
funds for the purposes set forth in subsection (a) of this Section, the trustees of the trust or foundation shall annually contribute funds in amounts set forth in subparagraph (2) of this subsection to the Citizens Utility Board created by the Citizens Utility Board Act; provided, however, that any such funds shall be used solely for the representation of the interests of utility consumers before the Illinois Commerce Commission, the Federal Energy Regulatory Commission, and the Federal Communications Commission and for the provision of consumer education on utility service and prices and on benefits and methods of energy conservation. Provided, however, that no part of such funds shall be used to support (i) any lobbying activity, (ii) activities related to fundraising, (iii) advertising or other marketing efforts regarding a particular utility, or (iv) solicitation of support for, or advocacy of, a particular position regarding any specific utility or a utility's docketed proceeding.
        (2) In the calendar year in which the trust or
    
foundation is first funded, the trustees shall contribute $1,000,000 to the Citizens Utility Board within 60 days after such trust or foundation is established; provided, however, that such contribution shall be made after December 31, 1999. In each of the 6 calendar years subsequent to the first contribution, if the trust or foundation is in existence, the trustees shall contribute to the Citizens Utility Board an amount equal to the total expenditures by such organization in the prior calendar year, as set forth in the report filed by the Citizens Utility Board with the chairman of such trust or foundation as required by subparagraph (3) of this subsection. Such subsequent contributions shall be made within 30 days of submission by the Citizens Utility Board of such report to the Chairman of the trust or foundation, but in no event shall any annual contribution by the trustees to the Citizens Utility Board exceed $1,000,000. Following such 7-year period, an Illinois statutory consumer protection agency may petition the trust or foundation for contributions to fund expenditures of the type identified in paragraph (1), but in no event shall annual contributions by the trust or foundation for such expenditures exceed $1,000,000.
        (3) The Citizens Utility Board shall file a report
    
with the chairman of such trust or foundation for each year in which it expends any funds received from the trust or foundation setting forth the amount of any expenditures (regardless of the source of funds for such expenditures) for: (i) the representation of the interests of utility consumers before the Illinois Commerce Commission, the Federal Energy Regulatory Commission, and the Federal Communications Commission, and (ii) the provision of consumer education on utility service and prices and on benefits and methods of energy conservation. Such report shall separately state the total amount of expenditures for the purposes or activities identified by items (i) and (ii) of this paragraph, the name and address of the external recipient of any such expenditure, if applicable, and the specific purposes or activities (including internal purposes or activities) for which each expenditure was made. Any report required by this subsection shall be filed with the chairman of such trust or foundation no later than March 31 of the year immediately following the year for which the report is required.
    (d) In addition to any other allocation and disbursement of funds in this Section, the trustees of the trust or foundation shall contribute an amount up to $125,000,000 (1) for deposit into the General Obligation Bond Retirement and Interest Fund held in the State treasury to assist in the repayment on general obligation bonds issued under subsection (d) of Section 7 of the General Obligation Bond Act, and (2) for deposit into funds administered by agencies with responsibility for environmental activities to assist in payment for environmental programs. The amount required to be contributed shall be provided to the trustees in a certification letter from the Director of the Bureau of the Budget that shall be provided no later than August 1, 2003. The payment from the trustees shall be paid to the State no later than December 31st following the receipt of the letter.
(Source: P.A. 93-32, eff. 6-20-03; 94-793, eff. 5-19-06.)

    (220 ILCS 5/16-111.2)
    Sec. 16-111.2. Provisions related to proposed utility transactions.
    (a) The General Assembly finds:
        (1) A transaction as described in paragraph (3) of

    
this subsection (a) will contribute to improved reliability of the electric supply system in Illinois which is one of the key purposes of the Illinois Electric Service Customer Choice and Rate Relief Law of 1997.
        (2) A transaction as described in paragraph (3) of
    
this subsection (a) is likely to promote additional investment in the existing generating assets and in the development of additional generation capacity in Illinois, and such change in ownership is in the public interest, consistent with the intent of the Illinois Electric Service Customer Choice and Rate Relief Law of 1997 and beneficial for the citizens of this State.
        (3) As of the date on which this amendatory Act of
    
1999 becomes law, an electric utility providing service to more than 1,000,000 customers in this State has proposed to sell or transfer to a single buyer 5 or more generating plants with a total net dependable capacity of 5000 megawatts or more pursuant to subsection (g) of Section 16-111.
        (4) Such electric utility anticipates receiving a
    
sale price or consideration as a result of such transaction exceeding 200% of the book value of these plants.
        (5) Such electric utility has presented to the
    
Governor and the leaders of the General Assembly a written commitment in which such electric utility agrees to expend $2,000,000,000 outside the corporate limits of any municipality with 1,000,000 or more inhabitants within such electric utility's service area, over a 6-year period beginning with this calendar year on projects, programs and improvements within its service area relating to transmission and distribution including, without limitation, infrastructure expansion, repair and replacement, capital investments, operations and maintenance, and vegetation management.
        (6) Such electric utility has committed that, if the
    
sale or transfer contemplated by paragraph (3) of this subsection is consummated on or before December 31, 1999, the electric utility shall make contributions totaling $250,000,000 to entities within this State for, among other purposes, environmental and clean coal initiatives pursuant to Section 16-111.1, which commitment includes a contribution of $25,000,000 to the Board of Trustees of Southern Illinois University for the purpose of funding programs or projects related to clean coal.
    (b) That, in light of the findings in paragraphs (1) and (2) of subsection (a) and, in this instance, the circumstances described in paragraphs (3) through (6) of subsection (a) and otherwise, the General Assembly hereby finds that allowing the generating facilities being acquired to be eligible facilities under the provisions of the National Energy Policy Act of 1992 that apply to exempt wholesale generators (A) will benefit consumers; (B) is in the public interest; and (C) does not violate the law of this State.
    (c) Nothing in this Section shall have any effect on the authority of the Commission under subsection (g) of Section 16-111 of this Act.
(Source: P.A. 91-50, eff. 6-30-99.)

    (220 ILCS 5/16-111.3)
    Sec. 16-111.3. Transition period earnings calculations. At such time as the Board of Governors of the Federal Reserve System ceases to include the monthly average yields of 30-year U.S. Treasury bonds in its weekly H.15 Statistical Release or successor publication, the Monthly Treasury Long-Term Average Rates (25 years and above) published by the Board of Governors of the Federal Reserve System in its weekly H.15 Statistical Release or successor publication shall instead be used to establish a rate for the purpose of calculating the Index defined in subsection (e) of Section 16-111 of this Act, and at such time, such Monthly Treasury Long-Term Average Rates (25 years and above) shall also be used in place of the monthly average yields of 30-year U.S. Treasury bonds in the rate of return calculation required by subsection (d) of Section 16-111. An electric utility shall also remove the effects, if any, of any impairment due to the application of Statement of Financial Accounting Standards No. 142, which was issued in June 2001, when making the calculations required by this Section or by subsections (d) and (e) of Section 16-111.
(Source: P.A. 92-537, eff. 6-6-02.)

    (220 ILCS 5/16-111.5)
    Sec. 16-111.5. Provisions relating to procurement.
    (a) An electric utility that on December 31, 2005 served at least 100,000 customers in Illinois shall procure power and energy for its eligible retail customers in accordance with the applicable provisions set forth in Section 1-75 of the Illinois Power Agency Act and this Section. A small multi-jurisdictional electric utility that on December 31, 2005 served less than 100,000 customers in Illinois may elect to procure power and energy for all or a portion of its eligible Illinois retail customers in accordance with the applicable provisions set forth in this Section and Section 1-75 of the Illinois Power Agency Act. This Section shall not apply to a small multi-jurisdictional utility until such time as a small multi-jurisdictional utility requests the Illinois Power Agency to prepare a procurement plan for its eligible retail customers. "Eligible retail customers" for the purposes of this Section means those retail customers that purchase power and energy from the electric utility under fixed-price bundled service tariffs, other than those retail customers whose service is declared or deemed competitive under Section 16-113 and those other customer groups specified in this Section, including self-generating customers, customers electing hourly pricing, or those customers who are otherwise ineligible for fixed-price bundled tariff service. Those customers that are excluded from the definition of "eligible retail customers" shall not be included in the procurement plan load requirements, and the utility shall procure any supply requirements, including capacity, ancillary services, and hourly priced energy, in the applicable markets as needed to serve those customers, provided that the utility may include in its procurement plan load requirements for the load that is associated with those retail customers whose service has been declared or deemed competitive pursuant to Section 16-113 of this Act to the extent that those customers are purchasing power and energy during one of the transition periods identified in subsection (b) of Section 16-113 of this Act.
    (b) A procurement plan shall be prepared for each electric utility consistent with the applicable requirements of the Illinois Power Agency Act and this Section. For purposes of this Section, Illinois electric utilities that are affiliated by virtue of a common parent company are considered to be a single electric utility. Small multi-jurisdictional utilities may request a procurement plan for a portion of or all of its Illinois load. Each procurement plan shall analyze the projected balance of supply and demand for eligible retail customers over a 5-year period with the first planning year beginning on June 1 of the year following the year in which the plan is filed. The plan shall specifically identify the wholesale products to be procured following plan approval, and shall follow all the requirements set forth in the Public Utilities Act and all applicable State and federal laws, statutes, rules, or regulations, as well as Commission orders. Nothing in this Section precludes consideration of contracts longer than 5 years and related forecast data. Unless specified otherwise in this Section, in the procurement plan or in the implementing tariff, any procurement occurring in accordance with this plan shall be competitively bid through a request for proposals process. Approval and implementation of the procurement plan shall be subject to review and approval by the Commission according to the provisions set forth in this Section. A procurement plan shall include each of the following components:
        (1) Hourly load analysis. This analysis shall

    
include:
            (i) multi-year historical analysis of hourly
        
loads;
            (ii) switching trends and competitive retail
        
market analysis;
            (iii) known or projected changes to future loads;
        
and
            (iv) growth forecasts by customer class.
        (2) Analysis of the impact of any demand side and
    
renewable energy initiatives. This analysis shall include:
            (i) the impact of demand response programs and
        
energy efficiency programs, both current and projected; for small multi-jurisdictional utilities, the impact of demand response and energy efficiency programs approved pursuant to Section 8-408 of this Act, both current and projected; and
            (ii) supply side needs that are projected to be
        
offset by purchases of renewable energy resources, if any.
        (3) A plan for meeting the expected load requirements
    
that will not be met through preexisting contracts. This plan shall include:
            (i) definitions of the different Illinois retail
        
customer classes for which supply is being purchased;
            (ii) the proposed mix of demand-response products
        
for which contracts will be executed during the next year. For small multi-jurisdictional electric utilities that on December 31, 2005 served fewer than 100,000 customers in Illinois, these shall be defined as demand-response products offered in an energy efficiency plan approved pursuant to Section 8-408 of this Act. The cost-effective demand-response measures shall be procured whenever the cost is lower than procuring comparable capacity products, provided that such products shall:
                (A) be procured by a demand-response provider
            
from eligible retail customers;
                (B) at least satisfy the demand-response
            
requirements of the regional transmission organization market in which the utility's service territory is located, including, but not limited to, any applicable capacity or dispatch requirements;
                (C) provide for customers' participation in
            
the stream of benefits produced by the demand-response products;
                (D) provide for reimbursement by the
            
demand-response provider of the utility for any costs incurred as a result of the failure of the supplier of such products to perform its obligations thereunder; and
                (E) meet the same credit requirements as
            
apply to suppliers of capacity, in the applicable regional transmission organization market;
            (iii) monthly forecasted system supply
        
requirements, including expected minimum, maximum, and average values for the planning period;
            (iv) the proposed mix and selection of standard
        
wholesale products for which contracts will be executed during the next year, separately or in combination, to meet that portion of its load requirements not met through pre-existing contracts, including but not limited to monthly 5 x 16 peak period block energy, monthly off-peak wrap energy, monthly 7 x 24 energy, annual 5 x 16 energy, annual off-peak wrap energy, annual 7 x 24 energy, monthly capacity, annual capacity, peak load capacity obligations, capacity purchase plan, and ancillary services;
            (v) proposed term structures for each wholesale
        
product type included in the proposed procurement plan portfolio of products; and
            (vi) an assessment of the price risk, load
        
uncertainty, and other factors that are associated with the proposed procurement plan; this assessment, to the extent possible, shall include an analysis of the following factors: contract terms, time frames for securing products or services, fuel costs, weather patterns, transmission costs, market conditions, and the governmental regulatory environment; the proposed procurement plan shall also identify alternatives for those portfolio measures that are identified as having significant price risk.
        (4) Proposed procedures for balancing loads. The
    
procurement plan shall include, for load requirements included in the procurement plan, the process for (i) hourly balancing of supply and demand and (ii) the criteria for portfolio re-balancing in the event of significant shifts in load.
    (c) The procurement process set forth in Section 1-75 of the Illinois Power Agency Act and subsection (e) of this Section shall be administered by a procurement administrator and monitored by a procurement monitor.
        (1) The procurement administrator shall:
            (i) design the final procurement process in
        
accordance with Section 1-75 of the Illinois Power Agency Act and subsection (e) of this Section following Commission approval of the procurement plan;
            (ii) develop benchmarks in accordance with
        
subsection (e)(3) to be used to evaluate bids; these benchmarks shall be submitted to the Commission for review and approval on a confidential basis prior to the procurement event;
            (iii) serve as the interface between the electric
        
utility and suppliers;
            (iv) manage the bidder pre-qualification and
        
registration process;
            (v) obtain the electric utilities' agreement to
        
the final form of all supply contracts and credit collateral agreements;
            (vi) administer the request for proposals process;
            (vii) have the discretion to negotiate to
        
determine whether bidders are willing to lower the price of bids that meet the benchmarks approved by the Commission; any post-bid negotiations with bidders shall be limited to price only and shall be completed within 24 hours after opening the sealed bids and shall be conducted in a fair and unbiased manner; in conducting the negotiations, there shall be no disclosure of any information derived from proposals submitted by competing bidders; if information is disclosed to any bidder, it shall be provided to all competing bidders;
            (viii) maintain confidentiality of supplier and
        
bidding information in a manner consistent with all applicable laws, rules, regulations, and tariffs;
            (ix) submit a confidential report to the
        
Commission recommending acceptance or rejection of bids;
            (x) notify the utility of contract counterparties
        
and contract specifics; and
            (xi) administer related contingency procurement
        
events.
        (2) The procurement monitor, who shall be retained by
    
the Commission, shall:
            (i) monitor interactions among the procurement
        
administrator, suppliers, and utility;
            (ii) monitor and report to the Commission on the
        
progress of the procurement process;
            (iii) provide an independent confidential report
        
to the Commission regarding the results of the procurement event;
            (iv) assess compliance with the procurement plans
        
approved by the Commission for each utility that on December 31, 2005 provided electric service to a least 100,000 customers in Illinois and for each small multi-jurisdictional utility that on December 31, 2005 served less than 100,000 customers in Illinois;
            (v) preserve the confidentiality of supplier and
        
bidding information in a manner consistent with all applicable laws, rules, regulations, and tariffs;
            (vi) provide expert advice to the Commission and
        
consult with the procurement administrator regarding issues related to procurement process design, rules, protocols, and policy-related matters; and
            (vii) consult with the procurement administrator
        
regarding the development and use of benchmark criteria, standard form contracts, credit policies, and bid documents.
    (d) Except as provided in subsection (j), the planning process shall be conducted as follows:
        (1) Beginning in 2008, each Illinois utility
    
procuring power pursuant to this Section shall annually provide a range of load forecasts to the Illinois Power Agency by July 15 of each year, or such other date as may be required by the Commission or Agency. The load forecasts shall cover the 5-year procurement planning period for the next procurement plan and shall include hourly data representing a high-load, low-load and expected-load scenario for the load of the eligible retail customers. The utility shall provide supporting data and assumptions for each of the scenarios.
        (2) Beginning in 2008, the Illinois Power Agency
    
shall prepare a procurement plan by August 15th of each year, or such other date as may be required by the Commission. The procurement plan shall identify the portfolio of demand-response and power and energy products to be procured. Cost-effective demand-response measures shall be procured as set forth in item (iii) of subsection (b) of this Section. Copies of the procurement plan shall be posted and made publicly available on the Agency's and Commission's websites, and copies shall also be provided to each affected electric utility. An affected utility shall have 30 days following the date of posting to provide comment to the Agency on the procurement plan. Other interested entities also may comment on the procurement plan. All comments submitted to the Agency shall be specific, supported by data or other detailed analyses, and, if objecting to all or a portion of the procurement plan, accompanied by specific alternative wording or proposals. All comments shall be posted on the Agency's and Commission's websites. During this 30-day comment period, the Agency shall hold at least one public hearing within each utility's service area for the purpose of receiving public comment on the procurement plan. Within 14 days following the end of the 30-day review period, the Agency shall revise the procurement plan as necessary based on the comments received and file the procurement plan with the Commission and post the procurement plan on the websites.
        (3) Within 5 days after the filing of the procurement
    
plan, any person objecting to the procurement plan shall file an objection with the Commission. Within 10 days after the filing, the Commission shall determine whether a hearing is necessary. The Commission shall enter its order confirming or modifying the procurement plan within 90 days after the filing of the procurement plan by the Illinois Power Agency.
        (4) The Commission shall approve the procurement
    
plan, including expressly the forecast used in the procurement plan, if the Commission determines that it will ensure adequate, reliable, affordable, efficient, and environmentally sustainable electric service at the lowest total cost over time, taking into account any benefits of price stability.
    (e) The procurement process shall include each of the following components:
        (1) Solicitation, pre-qualification, and registration
    
of bidders. The procurement administrator shall disseminate information to potential bidders to promote a procurement event, notify potential bidders that the procurement administrator may enter into a post-bid price negotiation with bidders that meet the applicable benchmarks, provide supply requirements, and otherwise explain the competitive procurement process. In addition to such other publication as the procurement administrator determines is appropriate, this information shall be posted on the Illinois Power Agency's and the Commission's websites. The procurement administrator shall also administer the prequalification process, including evaluation of credit worthiness, compliance with procurement rules, and agreement to the standard form contract developed pursuant to paragraph (2) of this subsection (e). The procurement administrator shall then identify and register bidders to participate in the procurement event.
        (2) Standard contract forms and credit terms and
    
instruments. The procurement administrator, in consultation with the utilities, the Commission, and other interested parties and subject to Commission oversight, shall develop and provide standard contract forms for the supplier contracts that meet generally accepted industry practices. Standard credit terms and instruments that meet generally accepted industry practices shall be similarly developed. The procurement administrator shall make available to the Commission all written comments it receives on the contract forms, credit terms, or instruments. If the procurement administrator cannot reach agreement with the applicable electric utility as to the contract terms and conditions, the procurement administrator must notify the Commission of any disputed terms and the Commission shall resolve the dispute. The terms of the contracts shall not be subject to negotiation by winning bidders, and the bidders must agree to the terms of the contract in advance so that winning bids are selected solely on the basis of price.
        (3) Establishment of a market-based price benchmark.
    
As part of the development of the procurement process, the procurement administrator, in consultation with the Commission staff, Agency staff, and the procurement monitor, shall establish benchmarks for evaluating the final prices in the contracts for each of the products that will be procured through the procurement process. The benchmarks shall be based on price data for similar products for the same delivery period and same delivery hub, or other delivery hubs after adjusting for that difference. The price benchmarks may also be adjusted to take into account differences between the information reflected in the underlying data sources and the specific products and procurement process being used to procure power for the Illinois utilities. The benchmarks shall be confidential but shall be provided to, and will be subject to Commission review and approval, prior to a procurement event.
        (4) Request for proposals competitive procurement
    
process. The procurement administrator shall design and issue a request for proposals to supply electricity in accordance with each utility's procurement plan, as approved by the Commission. The request for proposals shall set forth a procedure for sealed, binding commitment bidding with pay-as-bid settlement, and provision for selection of bids on the basis of price.
        (5) A plan for implementing contingencies in the
    
event of supplier default or failure of the procurement process to fully meet the expected load requirement due to insufficient supplier participation, Commission rejection of results, or any other cause.
            (i) Event of supplier default: In the event of
        
supplier default, the utility shall review the contract of the defaulting supplier to determine if the amount of supply is 200 megawatts or greater, and if there are more than 60 days remaining of the contract term. If both of these conditions are met, and the default results in termination of the contract, the utility shall immediately notify the Illinois Power Agency that a request for proposals must be issued to procure replacement power, and the procurement administrator shall run an additional procurement event. If the contracted supply of the defaulting supplier is less than 200 megawatts or there are less than 60 days remaining of the contract term, the utility shall procure power and energy from the applicable regional transmission organization market, including ancillary services, capacity, and day-ahead or real time energy, or both, for the duration of the contract term to replace the contracted supply; provided, however, that if a needed product is not available through the regional transmission organization market it shall be purchased from the wholesale market.
            (ii) Failure of the procurement process to fully
        
meet the expected load requirement: If the procurement process fails to fully meet the expected load requirement due to insufficient supplier participation or due to a Commission rejection of the procurement results, the procurement administrator, the procurement monitor, and the Commission staff shall meet within 10 days to analyze potential causes of low supplier interest or causes for the Commission decision. If changes are identified that would likely result in increased supplier participation, or that would address concerns causing the Commission to reject the results of the prior procurement event, the procurement administrator may implement those changes and rerun the request for proposals process according to a schedule determined by those parties and consistent with Section 1-75 of the Illinois Power Agency Act and this subsection. In any event, a new request for proposals process shall be implemented by the procurement administrator within 90 days after the determination that the procurement process has failed to fully meet the expected load requirement.
            (iii) In all cases where there is insufficient
        
supply provided under contracts awarded through the procurement process to fully meet the electric utility's load requirement, the utility shall meet the load requirement by procuring power and energy from the applicable regional transmission organization market, including ancillary services, capacity, and day-ahead or real time energy or both; provided, however, that if a needed product is not available through the regional transmission organization market it shall be purchased from the wholesale market.
        (6) The procurement process described in this
    
subsection is exempt from the requirements of the Illinois Procurement Code, pursuant to Section 20-10 of that Code.
    (f) Within 2 business days after opening the sealed bids, the procurement administrator shall submit a confidential report to the Commission. The report shall contain the results of the bidding for each of the products along with the procurement administrator's recommendation for the acceptance and rejection of bids based on the price benchmark criteria and other factors observed in the process. The procurement monitor also shall submit a confidential report to the Commission within 2 business days after opening the sealed bids. The report shall contain the procurement monitor's assessment of bidder behavior in the process as well as an assessment of the procurement administrator's compliance with the procurement process and rules. The Commission shall review the confidential reports submitted by the procurement administrator and procurement monitor, and shall accept or reject the recommendations of the procurement administrator within 2 business days after receipt of the reports.
    (g) Within 3 business days after the Commission decision approving the results of a procurement event, the utility shall enter into binding contractual arrangements with the winning suppliers using the standard form contracts; except that the utility shall not be required either directly or indirectly to execute the contracts if a tariff that is consistent with subsection (l) of this Section has not been approved and placed into effect for that utility.
    (h) The names of the successful bidders and the load weighted average of the winning bid prices for each contract type and for each contract term shall be made available to the public at the time of Commission approval of a procurement event. The Commission, the procurement monitor, the procurement administrator, the Illinois Power Agency, and all participants in the procurement process shall maintain the confidentiality of all other supplier and bidding information in a manner consistent with all applicable laws, rules, regulations, and tariffs. Confidential information, including the confidential reports submitted by the procurement administrator and procurement monitor pursuant to subsection (f) of this Section, shall not be made publicly available and shall not be discoverable by any party in any proceeding, absent a compelling demonstration of need, nor shall those reports be admissible in any proceeding other than one for law enforcement purposes.
    (i) Within 2 business days after a Commission decision approving the results of a procurement event or such other date as may be required by the Commission from time to time, the utility shall file for informational purposes with the Commission its actual or estimated retail supply charges, as applicable, by customer supply group reflecting the costs associated with the procurement and computed in accordance with the tariffs filed pursuant to subsection (l) of this Section and approved by the Commission.
    (j) Within 60 days following the effective date of this amendatory Act, each electric utility that on December 31, 2005 provided electric service to at least 100,000 customers in Illinois shall prepare and file with the Commission an initial procurement plan, which shall conform in all material respects to the requirements of the procurement plan set forth in subsection (b); provided, however, that the Illinois Power Agency Act shall not apply to the initial procurement plan prepared pursuant to this subsection. The initial procurement plan shall identify the portfolio of power and energy products to be procured and delivered for the period June 2008 through May 2009, and shall identify the proposed procurement administrator, who shall have the same experience and expertise as is required of a procurement administrator hired pursuant to Section 1-75 of the Illinois Power Agency Act. Copies of the procurement plan shall be posted and made publicly available on the Commission's website. The initial procurement plan may include contracts for renewable resources that extend beyond May 2009.
        (i) Within 14 days following filing of the initial
    
procurement plan, any person may file a detailed objection with the Commission contesting the procurement plan submitted by the electric utility. All objections to the electric utility's plan shall be specific, supported by data or other detailed analyses. The electric utility may file a response to any objections to its procurement plan within 7 days after the date objections are due to be filed. Within 7 days after the date the utility's response is due, the Commission shall determine whether a hearing is necessary. If it determines that a hearing is necessary, it shall require the hearing to be completed and issue an order on the procurement plan within 60 days after the filing of the procurement plan by the electric utility.
        (ii) The order shall approve or modify the
    
procurement plan, approve an independent procurement administrator, and approve or modify the electric utility's tariffs that are proposed with the initial procurement plan. The Commission shall approve the procurement plan if the Commission determines that it will ensure adequate, reliable, affordable, efficient, and environmentally sustainable electric service at the lowest total cost over time, taking into account any benefits of price stability.
    (k) In order to promote price stability for residential and small commercial customers during the transition to competition in Illinois, and notwithstanding any other provision of this Act, each electric utility subject to this Section shall enter into one or more multi-year financial swap contracts that become effective on the effective date of this amendatory Act. These contracts may be executed with generators and power marketers, including affiliated interests of the electric utility. These contracts shall be for a term of no more than 5 years and shall, for each respective utility or for any Illinois electric utilities that are affiliated by virtue of a common parent company and that are thereby considered a single electric utility for purposes of this subsection (k), not exceed in the aggregate 3,000 megawatts for any hour of the year. The contracts shall be financial contracts and not energy sales contracts. The contracts shall be executed as transactions under a negotiated master agreement based on the form of master agreement for financial swap contracts sponsored by the International Swaps and Derivatives Association, Inc. and shall be considered pre-existing contracts in the utilities' procurement plans for residential and small commercial customers. Costs incurred pursuant to a contract authorized by this subsection (k) shall be deemed prudently incurred and reasonable in amount and the electric utility shall be entitled to full cost recovery pursuant to the tariffs filed with the Commission.
    (k-5) In order to promote price stability for residential and small commercial customers during the infrastructure investment program described in subsection (b) of Section 16-108.5 of this Act, and notwithstanding any other provision of this Act or the Illinois Power Agency Act, for each electric utility that serves more than one million retail customers in Illinois, the Illinois Power Agency shall conduct a procurement event within 120 days after October 26, 2011 (the effective date of Public Act 97-616) and may procure contracts for energy and renewable energy credits for the period June 1, 2013 through December 31, 2017 that satisfy the requirements of this subsection (k-5), including the benchmarks described in this subsection. These contracts shall be entered into as the result of a competitive procurement event, and, to the extent that any provisions of this Section or the Illinois Power Agency Act do not conflict with this subsection (k-5), such provisions shall apply to the procurement event. The energy contracts shall be for 24 hour by 7 day supply over a term that runs from the first delivery year through December 31, 2017. For a utility that serves over 2 million customers, the energy contracts shall be multi-year with pricing escalating at 2.5% per annum. The energy contracts may be designed as financial swaps or may require physical delivery.
    Within 30 days of October 26, 2011 (the effective date of Public Act 97-616), each such utility shall submit to the Agency updated load forecasts for the period June 1, 2013 through December 31, 2017. The megawatt volume of the contracts shall be based on the updated load forecasts of the minimum monthly on-peak or off-peak average load requirements shown in the forecasts, taking into account any existing energy contracts in effect as well as the expected migration of the utility's customers to alternative retail electric suppliers. The renewable energy credit volume shall be based on the number of credits that would satisfy the requirements of subsection (c) of Section 1-75 of the Illinois Power Agency Act, subject to the rate impact caps and other provisions of subsection (c) of Section 1-75 of the Illinois Power Agency Act. The evaluation of contract bids in the competitive procurement events for energy and for renewable energy credits shall incorporate price benchmarks set collaboratively by the Agency, the procurement administrator, the staff of the Commission, and the procurement monitor. If the contracts are swap contracts, then they shall be executed as transactions under a negotiated master agreement based on the form of master agreement for financial swap contracts sponsored by the International Swaps and Derivatives Association, Inc. Costs incurred pursuant to a contract authorized by this subsection (k-5) shall be deemed prudently incurred and reasonable in amount and the electric utility shall be entitled to full cost recovery pursuant to the tariffs filed with the Commission.
    The cost of administering the procurement event described in this subsection (k-5) shall be paid by the winning supplier or suppliers to the procurement administrator through a supplier fee. In the event that there is no winning supplier for a particular utility, such utility will pay the procurement administrator for the costs associated with the procurement event, and those costs shall not be a recoverable expense. Nothing in this subsection (k-5) is intended to alter the recovery of costs for any other procurement event.
    (l) An electric utility shall recover its costs incurred under this Section, including, but not limited to, the costs of procuring power and energy demand-response resources under this Section. The utility shall file with the initial procurement plan its proposed tariffs through which its costs of procuring power that are incurred pursuant to a Commission-approved procurement plan and those other costs identified in this subsection (l), will be recovered. The tariffs shall include a formula rate or charge designed to pass through both the costs incurred by the utility in procuring a supply of electric power and energy for the applicable customer classes with no mark-up or return on the price paid by the utility for that supply, plus any just and reasonable costs that the utility incurs in arranging and providing for the supply of electric power and energy. The formula rate or charge shall also contain provisions that ensure that its application does not result in over or under recovery due to changes in customer usage and demand patterns, and that provide for the correction, on at least an annual basis, of any accounting errors that may occur. A utility shall recover through the tariff all reasonable costs incurred to implement or comply with any procurement plan that is developed and put into effect pursuant to Section 1-75 of the Illinois Power Agency Act and this Section, including any fees assessed by the Illinois Power Agency, costs associated with load balancing, and contingency plan costs. The electric utility shall also recover its full costs of procuring electric supply for which it contracted before the effective date of this Section in conjunction with the provision of full requirements service under fixed-price bundled service tariffs subsequent to December 31, 2006. All such costs shall be deemed to have been prudently incurred. The pass-through tariffs that are filed and approved pursuant to this Section shall not be subject to review under, or in any way limited by, Section 16-111(i) of this Act.
    (m) The Commission has the authority to adopt rules to carry out the provisions of this Section. For the public interest, safety, and welfare, the Commission also has authority to adopt rules to carry out the provisions of this Section on an emergency basis immediately following the effective date of this amendatory Act.
    (n) Notwithstanding any other provision of this Act, any affiliated electric utilities that submit a single procurement plan covering their combined needs may procure for those combined needs in conjunction with that plan, and may enter jointly into power supply contracts, purchases, and other procurement arrangements, and allocate capacity and energy and cost responsibility therefor among themselves in proportion to their requirements.
    (o) On or before June 1 of each year, the Commission shall hold an informal hearing for the purpose of receiving comments on the prior year's procurement process and any recommendations for change.
    (p) An electric utility subject to this Section may propose to invest, lease, own, or operate an electric generation facility as part of its procurement plan, provided the utility demonstrates that such facility is the least-cost option to provide electric service to eligible retail customers. If the facility is shown to be the least-cost option and is included in a procurement plan prepared in accordance with Section 1-75 of the Illinois Power Agency Act and this Section, then the electric utility shall make a filing pursuant to Section 8-406 of this Act, and may request of the Commission any statutory relief required thereunder. If the Commission grants all of the necessary approvals for the proposed facility, such supply shall thereafter be considered as a pre-existing contract under subsection (b) of this Section. The Commission shall in any order approving a proposal under this subsection specify how the utility will recover the prudently incurred costs of investing in, leasing, owning, or operating such generation facility through just and reasonable rates charged to eligible retail customers. Cost recovery for facilities included in the utility's procurement plan pursuant to this subsection shall not be subject to review under or in any way limited by the provisions of Section 16-111(i) of this Act. Nothing in this Section is intended to prohibit a utility from filing for a fuel adjustment clause as is otherwise permitted under Section 9-220 of this Act.
(Source: P.A. 97-325, eff. 8-12-11; 97-616, eff. 10-26-11; 97-813, eff. 7-13-12.)

    (220 ILCS 5/16-111.5A)
    Sec. 16-111.5A. Provisions relating to electric rate relief.
    (a) The General Assembly finds that action must be taken in order to mitigate the 2007 electric rate increases approved for residential and certain nonresidential customers served by the State's largest electric utilities in 2007. The General Assembly further finds that although various means of providing rate relief have been proposed, including imposition of a rate freeze on the electric utilities or a tax on generation within the State, the establishment of voluntary rate relief programs provides the most immediate and certain means of providing that rate relief. Accordingly, if the residential customer electric service rates that were charged to residential customers beginning January 2, 2007 by an electric utility that on December 31, 2005 provided electric service to at least 100,000 customers in Illinois resulted in an annual increase of more than 20% in an electric utility's average rate charged to residential customers for bundled electric service, those electric utilities and their holding companies or other affiliates, and any other company owning generation in this State or its affiliates, may, notwithstanding any other provisions of this Act, and without obtaining any approvals from the Commission or any other agency, regardless of whether any such approval would otherwise be required, establish and make payments to provide funds that can be used to provide rate relief beginning on the effective date of this amendatory Act of the 95th General Assembly through July 31, 2011.
    (b) For purposes of this Section, the "Ameren Utilities" means Illinois Power Company, Central Illinois Public Service Company, and Central Illinois Light Company.
    (c) For purposes of this Section, the "Generators" means Exelon Generation Company, LLC; Ameren Energy Resources Generating Company; Ameren Energy Marketing Company; Ameren Energy Generating Company; MidAmerican Energy Company; Midwest Generation, LLC; and Dynegy Holdings Inc.; and may include non-utility affiliates of the entities named in this subsection.
    (d) For purposes of this Section, "Rate Relief Agreements" means the 2 Rate Relief Funding Agreements, the Escrow Funding Agreement, and the Illinois Power Agency Funding Agreement that Commonwealth Edison Company, the Ameren Utilities, and Generators have entered into with the Illinois Attorney General on behalf of the People of the State of Illinois for the purpose of providing $1,001,000,000 to be used to fund rate relief programs for customers of Commonwealth Edison Company and the Ameren Utilities and for the Illinois Power Agency Trust Fund and that become effective on the effective date of this amendatory Act of the 95th General Assembly. The Rate Relief Agreements have been filed with the Illinois Secretary of State Index Department and designated as "95-GA-C01" through "95-GA-C04" inclusive. The Illinois Attorney General has the right to enforce the provisions of all of the Rate Relief Agreements on behalf of the People of the State of Illinois or the Illinois Power Agency, or both, as appropriate.
    (e) Subject to the terms, conditions, and contingencies of the Rate Relief Agreements, Commonwealth Edison Company will apply a total of $488,000,000 in rate relief to residential and certain nonresidential customers from 2007 through 2010. Commonwealth Edison Company will apply bill credits for all of its residential customers in its service territory in the following amounts: $250,000,000 in 2007, $125,500,000 in 2008, and $36,000,000 in 2009. Any undisbursed rate relief funds shall be applied to the targeted programs. Commonwealth Edison Company will provide rate relief for residential and certain nonresidential customers through targeted programs in the following amounts: $33,000,000 in 2007, $18,000,000 in 2008, $15,500,000 in 2009, and $10,000,000 in 2010. Subject to the terms, conditions, and contingencies of the Rate Relief Agreements, the targeted programs for 2007 consist of the following, some of which are already underway and, in the aggregate, therefore total more than $33,000,000:
        (1) an electric space heating customer relief program

    
costing approximately $8,000,000 designed to lower the average percentage increase of residential electric space heating customers to rate increases similar to other residential customers;
        (2) a summer assistance program costing approximately
    
$10,300,000 for working families and low-income customers, including low-income seniors;
        (3) a residential rate relief program costing
    
approximately $5,500,000 for working families and low-income customers, including low-income seniors, with higher than average rate increases (over 30%);
        (4) a residential special hardship program costing
    
approximately $5,000,000 to address special circumstances and hardships;
        (5) a nonresidential special hardship program costing
    
approximately $1,500,000 to address special circumstances and hardships;
        (6) a relief program for the common area accounts of
    
apartment building owners and condominium associations costing approximately $4,500,000 designed to reduce rate increases for these customers to rate increases similar to those for residential customers and to mitigate the impact of their rate increase;
        (7) a weatherization assistance program for electric
    
space heating low-income customers costing approximately $3,900,000 designed to provide energy efficiency assistance; and
        (8) energy efficiency, environmental, education, and
    
assistance programs costing approximately $5,000,000 designed to promote the use of energy efficiency programs and services by residential customers, maintenance and upgrades of a website that allows those customers to analyze their energy usage and provides incentives for the purchase of energy efficient products, the provision of energy efficient light bulbs to residential customers at a discount, and free efficient light bulbs and other assistance to low-income customers.
    Based on the outcome of these targeted programs, Commonwealth Edison Company will design and implement, subject to the terms, conditions, and contingencies of the Rate Relief Agreements, targeted programs for working families, seniors, and other customers in need in 2008, 2009, and 2010.
    (f) Subject to the terms, conditions, and contingencies of the Rate Relief Agreements, the Ameren Utilities will apply a total of $488,000,000 in rate relief to residential and certain nonresidential customers from 2007 through 2010. The Ameren Utilities will apply bill credits for all of their residential customers in their service territories in the following aggregate amounts: $213,000,000 in 2007, $109,000,000 in 2008, and $78,000,000 in 2009. The Ameren Utilities will apply bill credits to certain nonresidential customers in the following aggregate amounts: $26,000,000 in 2007, $11,000,000 in 2008, and $11,000,000 in 2009. Any undisbursed rate relief funds shall be applied to the targeted programs. The Ameren Utilities will provide rate relief for residential and certain nonresidential customers through targeted programs in the following amounts: $13,500,000 in 2007, $13,500,000 in 2008, $7,500,000 in 2009, and $5,500,000 in 2010. Subject to the terms, conditions and contingencies of the Rate Relief Agreements, the targeted programs consist of the following for 2007:
        (1) a cooling assistance program costing
    
approximately $2,000,000 to provide donations to the Low Income Home Energy Assistance Program;
        (2) a bill payment assistance program costing
    
approximately $2,000,000 for working families and low-income customers, including low-income seniors;
        (3) a residential special hardship program costing
    
approximately $2,000,000 to address special circumstances and hardships;
        (4) a nonresidential special hardship program costing
    
approximately $2,000,000 to address special circumstances and hardships;
        (5) a percent-of-income payment program pilot costing
    
approximately $2,500,000 that will be designed to determine for low-income electric space heating customers if paying a percentage of income for their electricity will make electricity more affordable and promote regular paying habits;
        (6) a weatherization assistance program for all
    
electric space heating low-income customers costing approximately $1,000,000 designed to provide energy efficiency assistance;
        (7) a compact fluorescent light bulb distribution
    
program costing approximately $1,000,000 designed to provide energy efficient light bulbs to residential customers at a discount; and
        (8) a municipal street lighting conversion program
    
costing approximately $1,000,000 to convert existing street lights to more efficient lights at a discount.
    Based on the outcome of these targeted programs, the Ameren Utilities will design and implement, subject to the terms, conditions, and contingencies of the Rate Relief Agreements, targeted programs for working families, seniors, and other customers in need in 2008, 2009, and 2010.
    In addition, the Ameren Utilities voluntarily agree to waive outstanding late payment charges associated with unpaid electric bills for usage on and after January 2, 2007, through the September 2007 billing period.
    (g) Programs that use funds that are provided by electric utilities and their holding companies or other affiliates, and any other company owning generation in this State or its affiliates, to reduce utility bills, or to otherwise offset costs incurred by the utilities in mitigating rate increases for certain customer groups, may be implemented through tariffs that are filed with and reviewed by the Commission. If a utility elects to file tariffs with the Commission to implement all or a portion of the programs, those tariffs shall, regardless of the date actually filed, be deemed accepted and approved, and shall become effective, on the effective date of this amendatory Act of the 95th General Assembly. The electric utilities whose customers benefit from the funds that are disbursed as contemplated in this Section shall file annual reports documenting the disbursement of those funds with the Commission and the Illinois Attorney General. The Commission has the authority to audit disbursement of the funds to ensure they were disbursed consistently with this Section.
    (h) Nothing in this Section shall be interpreted to limit the Commission's general authority over ratemaking.
    (i) Subject to the terms, conditions, and contingencies of the Rate Relief Agreements, the Generators are providing a total of $25,000,000 to the Illinois Power Agency Trust Fund.
    (j) None of the contributions by Commonwealth Edison Company or the Ameren Utilities pursuant to this Section may be recovered in rates.
    (k) Nothing in this Section shall be interpreted to limit the authority or right of the Illinois Attorney General, under the terms of the Rate Relief Agreements, to review or audit documents, make demands, or file suit or to take other action to enforce the provisions of the Rate Relief Agreements.
(Source: P.A. 95-481, eff. 8-28-07.)

    (220 ILCS 5/16-111.5B)
    Sec. 16-111.5B. Provisions relating to energy efficiency procurement.
    (a) Beginning in 2012, procurement plans prepared pursuant to Section 16-111.5 of this Act shall be subject to the following additional requirements:
        (1) The analysis included pursuant to paragraph (2)

    
of subsection (b) of Section 16-111.5 shall also include the impact of energy efficiency building codes or appliance standards, both current and projected.
        (2) The procurement plan components described in
    
subsection (b) of Section 16-111.5 shall also include an assessment of opportunities to expand the programs promoting energy efficiency measures that have been offered under plans approved pursuant to Section 8-103 of this Act or to implement additional cost-effective energy efficiency programs or measures.
        (3) In addition to the information provided pursuant
    
to paragraph (1) of subsection (d) of Section 16-111.5 of this Act, each Illinois utility procuring power pursuant to that Section shall annually provide to the Illinois Power Agency by July 15 of each year, or such other date as may be required by the Commission or Agency, an assessment of cost-effective energy efficiency programs or measures that could be included in the procurement plan. The assessment shall include the following:
            (A) A comprehensive energy efficiency potential
        
study for the utility's service territory that was completed within the past 3 years.
            (B) Beginning in 2014, the most recent analysis
        
submitted pursuant to Section 8-103A of this Act and approved by the Commission under subsection (f) of Section 8-103 of this Act.
            (C) Identification of new or expanded
        
cost-effective energy efficiency programs or measures that are incremental to those included in energy efficiency and demand-response plans approved by the Commission pursuant to Section 8-103 of this Act and that would be offered to all retail customers whose electric service has not been declared competitive under Section 16-113 of this Act and who are eligible to purchase power and energy from the utility under fixed-price bundled service tariffs, regardless of whether such customers actually do purchase such power and energy from the utility.
            (D) Analysis showing that the new or expanded
        
cost-effective energy efficiency programs or measures would lead to a reduction in the overall cost of electric service.
            (E) Analysis of how the cost of procuring
        
additional cost-effective energy efficiency measures compares over the life of the measures to the prevailing cost of comparable supply.
            (F) An energy savings goal, expressed in
        
megawatt-hours, for the year in which the measures will be implemented.
            (G) For each expanded or new program, the
        
estimated amount that the program may reduce the agency's need to procure supply.
        In preparing such assessments, a utility shall
    
conduct an annual solicitation process for purposes of requesting proposals from third-party vendors, the results of which shall be provided to the Agency as part of the assessment, including documentation of all bids received. The utility shall develop requests for proposals consistent with the manner in which it develops requests for proposals under plans approved pursuant to Section 8-103 of this Act, which considers input from the Agency and interested stakeholders.
        (4) The Illinois Power Agency shall include in the
    
procurement plan prepared pursuant to paragraph (2) of subsection (d) of Section 16-111.5 of this Act energy efficiency programs and measures it determines are cost-effective and the associated annual energy savings goal included in the annual solicitation process and assessment submitted pursuant to paragraph (3) of this subsection (a).
        (5) Pursuant to paragraph (4) of subsection (d) of
    
Section 16-111.5 of this Act, the Commission shall also approve the energy efficiency programs and measures included in the procurement plan, including the annual energy savings goal, if the Commission determines they fully capture the potential for all achievable cost-effective savings, to the extent practicable, and otherwise satisfy the requirements of Section 8-103 of this Act.
        In the event the Commission approves the procurement
    
of additional energy efficiency, it shall reduce the amount of power to be procured under the procurement plan to reflect the additional energy efficiency and shall direct the utility to undertake the procurement of such energy efficiency, which shall not be subject to the requirements of subsection (e) of Section 16-111.5 of this Act. The utility shall consider input from the Agency and interested stakeholders on the procurement and administration process.
        (6) An electric utility shall recover its costs
    
incurred under this Section related to the implementation of energy efficiency programs and measures approved by the Commission in its order approving the procurement plan under Section 16-111.5 of this Act, including, but not limited to, all costs associated with complying with this Section and all start-up and administrative costs and the costs for any evaluation, measurement, and verification of the measures, from all retail customers whose electric service has not been declared competitive under Section 16-113 of this Act and who are eligible to purchase power and energy from the utility under fixed-price bundled service tariffs, regardless of whether such customers actually do purchase such power and energy from the utility through the automatic adjustment clause tariff established pursuant to Section 8-103 of this Act, provided, however, that the limitations described in subsection (d) of that Section shall not apply to the costs incurred pursuant to this Section or Section 16-111.7 of this Act.
    (b) For purposes of this Section, the term "energy efficiency" shall have the meaning set forth in Section 1-10 of the Illinois Power Agency Act, and the term "cost-effective" shall have the meaning set forth in subsection (a) of Section 8-103 of this Act.
(Source: P.A. 97-616, eff. 10-26-11; 97-824, eff. 7-18-12.)

    (220 ILCS 5/16-111.6)
    Sec. 16-111.6. Termination of utility service to electric space-heating customers. Notwithstanding any other provision of this Act or any other law to the contrary, a public utility that, on December 31, 2005, served more than 100,000 electric customers in Illinois may not, prior to September 1, 2007, terminate electric service to a residential electric space-heating customer for non-payment. For 2007 and every year thereafter, such an electric utility shall not terminate electric service to a residential space-heating customer for non-payment from December 1 through March 31.
(Source: P.A. 95-481, eff. 8-28-07.)

    (220 ILCS 5/16-111.7)
    Sec. 16-111.7. On-bill financing program; electric utilities.
    (a) The Illinois General Assembly finds that Illinois homes and businesses have the potential to save energy through conservation and cost-effective energy efficiency measures. Programs created pursuant to this Section will allow utility customers to purchase cost-effective energy efficiency measures, including measures set forth in a Commission-approved energy efficiency and demand-response plan under Section 8-103 of this Act, with no required initial upfront payment, and to pay the cost of those products and services over time on their utility bill.
    (b) Notwithstanding any other provision of this Act, an electric utility serving more than 100,000 customers on January 1, 2009 shall offer a Commission-approved on-bill financing program ("program") that allows its eligible retail customers, as that term is defined in Section 16-111.5 of this Act, who own a residential single family home, duplex, or other residential building with 4 or less units, or condominium at which the electric service is being provided (i) to borrow funds from a third party lender in order to purchase electric energy efficiency measures approved under the program for installation in such home or condominium without any required upfront payment and (ii) to pay back such funds over time through the electric utility's bill. Based upon the process described in subsection (b-5) of this Section, small commercial customers who own the premises at which electric service is being provided may be included in such program. After receiving a request from an electric utility for approval of a proposed program and tariffs pursuant to this Section, the Commission shall render its decision within 120 days. If no decision is rendered within 120 days, then the request shall be deemed to be approved.
    Beginning no later than December 31, 2013, an electric utility subject to this subsection (b) shall also offer its program to eligible retail customers that own multifamily residential or mixed-use buildings with no more than 50 residential units, provided, however, that such customers must either be a residential customer or small commercial customer and may not use the program in such a way that repayment of the cost of energy efficiency measures is made through tenants' utility bills. An electric utility may impose a per site loan limit not to exceed $150,000. The program, and loans issued thereunder, shall only be offered to customers of the utility that meet the requirements of this Section and that also have an electric service account at the premises where the energy efficiency measures being financed shall be installed.
    For purposes of this Section, "small commercial customer" means, for an electric utility serving more than 3,000,000 retail customers, those customers having peak demand of less than 100 kilowatts, and, for an electric utility serving less than 3,000,000 retail customers, those customers having peak demand of less than 150 kilowatts; provided, however, that in the event the Commission, after the effective date of this amendatory Act of the 98th General Assembly, approves changes to a utility's tariffs that reflects new or revised demand criteria for the utility's customer rate classifications, then the utility may file a petition with the Commission to revise the applicable definition of a small commercial customer to reflect the new or revised demand criteria for the purposes of this Section. After notice and hearing, the Commission shall enter an order approving, or approving with modification, the revised definition within 60 days after the utility files the petition.
    (b-5) Within 30 days after the effective date of this amendatory Act of the 96th General Assembly, the Commission shall convene a workshop process during which interested participants may discuss issues related to the program, including program design, eligible electric energy efficiency measures, vendor qualifications, and a methodology for ensuring ongoing compliance with such qualifications, financing, sample documents such as request for proposals, contracts and agreements, dispute resolution, pre-installment and post-installment verification, and evaluation. The workshop process shall be completed within 150 days after the effective date of this amendatory Act of the 96th General Assembly.
    (c) Not later than 60 days following completion of the workshop process described in subsection (b-5) of this Section, each electric utility subject to subsection (b) of this Section shall submit a proposed program to the Commission that contains the following components:
        (1) A list of recommended electric energy efficiency

    
measures that will be eligible for on-bill financing. An eligible electric energy efficiency measure ("measure") shall be a product or service for which one or more of the following is true:
            (A) (blank);
            (B) the projected electricity savings (determined
        
by rates in effect at the time of purchase) are sufficient to cover the costs of implementing the measures, including finance charges and any program fees not recovered pursuant to subsection (f) of this Section; or
            (C) the product or service is included in a
        
Commission-approved energy efficiency and demand-response plan under Section 8-103 of this Act.
        (2) The electric utility shall issue a request for
    
proposals ("RFP") to lenders for purposes of providing financing to participants to pay for approved measures. The RFP criteria shall include, but not be limited to, the interest rate, origination fees, and credit terms. The utility shall select the winning bidders based on its evaluation of these criteria, with a preference for those bids containing the rates, fees, and terms most favorable to participants;
        (3) The utility shall work with the lenders selected
    
pursuant to the RFP process, and with vendors, to establish the terms and processes pursuant to which a participant can purchase eligible electric energy efficiency measures using the financing obtained from the lender. The vendor shall explain and offer the approved financing packaging to those customers identified in subsection (b) of this Section and shall assist customers in applying for financing. As part of the process, vendors shall also provide to participants information about any other incentives that may be available for the measures.
        (4) The lender shall conduct credit checks or
    
undertake other appropriate measures to limit credit risk, and shall review and approve or deny financing applications submitted by customers identified in subsection (b) of this Section. Following the lender's approval of financing and the participant's purchase of the measure or measures, the lender shall forward payment information to the electric utility, and the utility shall add as a separate line item on the participant's utility bill a charge showing the amount due under the program each month.
        (5) A loan issued to a participant pursuant to the
    
program shall be the sole responsibility of the participant, and any dispute that may arise concerning the loan's terms, conditions, or charges shall be resolved between the participant and lender. Upon transfer of the property title for the premises at which the participant receives electric service from the utility or the participant's request to terminate service at such premises, the participant shall pay in full its electric utility bill, including all amounts due under the program, provided that this obligation may be modified as provided in subsection (g) of this Section. Amounts due under the program shall be deemed amounts owed for residential and, as appropriate, small commercial electric service.
        (6) The electric utility shall remit payment in full
    
to the lender each month on behalf of the participant. In the event a participant defaults on payment of its electric utility bill, the electric utility shall continue to remit all payments due under the program to the lender, and the utility shall be entitled to recover all costs related to a participant's nonpayment through the automatic adjustment clause tariff established pursuant to Section 16-111.8 of this Act. In addition, the electric utility shall retain a security interest in the measure or measures purchased under the program, and the utility retains its right to disconnect a participant that defaults on the payment of its utility bill.
        (7) The total outstanding amount financed under the
    
program in this subsection and subsection (c-5) of this Section shall not exceed $2.5 million for an electric utility or electric utilities under a single holding company, provided that the electric utility or electric utilities may petition the Commission for an increase in such amount.
    (c-5) Within 120 days after the effective date of this amendatory Act of the 98th General Assembly, each electric utility subject to the requirements of this Section shall submit an informational filing to the Commission that describes its plan for implementing the provisions of this amendatory Act of the 98th General Assembly on or before December 31, 2013. Such filing shall also describe how the electric utility shall coordinate its program with any gas utility or utilities that provide gas service to buildings within the electric utility's service territory so that it is practical and feasible for the owner of a multifamily building to make a single application to access loans for both gas and electric energy efficiency measures in any individual building.
    (d) A program approved by the Commission shall also include the following criteria and guidelines for such program:
        (1) guidelines for financing of measures installed
    
under a program, including, but not limited to, RFP criteria and limits on both individual loan amounts and the duration of the loans;
        (2) criteria and standards for identifying and
    
approving measures;
        (3) qualifications of vendors that will market or
    
install measures, as well as a methodology for ensuring ongoing compliance with such qualifications;
        (4) sample contracts and agreements necessary to
    
implement the measures and program; and
        (5) the types of data and information that utilities
    
and vendors participating in the program shall collect for purposes of preparing the reports required under subsection (g) of this Section.
    (e) The proposed program submitted by each electric utility shall be consistent with the provisions of this Section that define operational, financial and billing arrangements between and among program participants, vendors, lenders, and the electric utility.
    (f) An electric utility shall recover all of the prudently incurred costs of offering a program approved by the Commission pursuant to this Section, including, but not limited to, all start-up and administrative costs and the costs for program evaluation. All prudently incurred costs under this Section shall be recovered from the residential and small commercial retail customer classes eligible to participate in the program through the automatic adjustment clause tariff established pursuant to Section 8-103 of this Act.
    (g) An independent evaluation of a program shall be conducted after 3 years of the program's operation. The electric utility shall retain an independent evaluator who shall evaluate the effects of the measures installed under the program and the overall operation of the program, including, but not limited to, customer eligibility criteria and whether the payment obligation for permanent electric energy efficiency measures that will continue to provide benefits of energy savings should attach to the meter location. As part of the evaluation process, the evaluator shall also solicit feedback from participants and interested stakeholders. The evaluator shall issue a report to the Commission on its findings no later than 4 years after the date on which the program commenced, and the Commission shall issue a report to the Governor and General Assembly including a summary of the information described in this Section as well as its recommendations as to whether the program should be discontinued, continued with modification or modifications or continued without modification, provided that any recommended modifications shall only apply prospectively and to measures not yet installed or financed.
    (h) An electric utility offering a Commission-approved program pursuant to this Section shall not be required to comply with any other statute, order, rule, or regulation of this State that may relate to the offering of such program, provided that nothing in this Section is intended to limit the electric utility's obligation to comply with this Act and the Commission's orders, rules, and regulations, including Part 280 of Title 83 of the Illinois Administrative Code.
    (i) The source of a utility customer's electric supply shall not disqualify a customer from participation in the utility's on-bill financing program. Customers of alternative retail electric suppliers may participate in the program under the same terms and conditions applicable to the utility's supply customers.
(Source: P.A. 97-616, eff. 10-26-11; 98-586, eff. 8-27-13.)

    (220 ILCS 5/16-111.8)
    Sec. 16-111.8. Automatic adjustment clause tariff; uncollectibles.
    (a) An electric utility shall be permitted, at its election, to recover through an automatic adjustment clause tariff the incremental difference between its actual uncollectible amount as set forth in Account 904 in the utility's most recent annual FERC Form 1 and the uncollectible amount included in the utility's rates for the period reported in such annual FERC Form 1. The Commission may, in a proceeding to review a general rate case filed subsequent to the effective date of the tariff established under this Section, prospectively switch from using the actual uncollectible amount set forth in Account 904 to using net write-offs in such tariff, but only if net write-offs are also used to determine the utility's uncollectible amount in rates. In the event the Commission requires such a change, it shall be made effective at the beginning of the first full calendar year after the new rates approved in such proceeding are first placed in effect and an adjustment shall be made, if necessary, to ensure the change does not result in double-recovery or unrecovered uncollectible amounts for any year. For purposes of this Section, "uncollectible amount" means the expense set forth in Account 904 of the utility's FERC Form 1 or cost of net write-offs as appropriate. In the event the utility's rates change during the period of time reported in its most recent annual FERC Form 1, the uncollectible amount included in the utility's rates during such period of time for purposes of this Section will be a weighted average, based on revenues earned during such period by the utility under each set of rates, of the uncollectible amount included in the utility's rates at the beginning of such period and at the end of such period. This difference may either be a charge or a credit to customers depending on whether the uncollectible amount is more or less than the uncollectible amount then included in the utility's rates.
    (b) The tariff may be established outside the context of a general rate case filing and shall specify the terms of any applicable audit. The Commission shall review and by order approve, or approve as modified, the proposed tariff within 180 days after the date on which it is filed. Charges and credits under the tariff shall be allocated to the appropriate customer class or classes. In addition, customers who purchase their electric supply from an alternative retail electric supplier shall not be charged by the utility for uncollectible amounts associated with electric supply provided by the utility to the utility's customers, provided that nothing in this Section is intended to affect or alter the rights and obligations imposed pursuant to Section 16-118 of this Act and any Commission order issued thereunder. Upon approval of the tariff, the utility shall, based on the 2008 FERC Form 1, apply the appropriate credit or charge based on the full year 2008 amounts for the remainder of the 2010 calendar year. Starting with the 2009 FERC Form 1 reporting period and each subsequent period, the utility shall apply the appropriate credit or charge over a 12-month period beginning with the June billing period and ending with the May billing period, with the first such billing period beginning June 2010.
    (c) The approved tariff shall provide that the utility shall file a petition with the Commission annually, no later than August 31st, seeking initiation of an annual review to reconcile all amounts collected with the actual uncollectible amount in the prior period. As part of its review, the Commission shall verify that the utility collects no more and no less than its actual uncollectible amount in each applicable FERC Form 1 reporting period. The Commission shall review the prudence and reasonableness of the utility's actions to pursue minimization and collection of uncollectibles which shall include, at a minimum, the 6 enumerated criteria set forth in this Section. The Commission shall determine any required adjustments and may include suggestions for prospective changes in current practices. Nothing in this Section or the implementing tariffs shall affect or alter the electric utility's existing obligation to pursue collection of uncollectibles or the electric utility's right to disconnect service. A utility that has in effect a tariff authorized by this Section shall pursue minimization of and collection of uncollectibles through the following activities, including, but not limited to:
        (1) identifying customers with late payments;
        (2) contacting the customers in an effort to obtain

    
payment;
        (3) providing delinquent customers with information
    
about possible options, including payment plans and assistance programs;
        (4) serving disconnection notices;
        (5) implementing disconnections based on the level of
    
uncollectibles; and
        (6) pursuing collection activities based on the
    
level of uncollectibles.
    (d) Nothing in this Section shall be construed to require a utility to immediately disconnect service for nonpayment.
(Source: P.A. 96-33, eff. 7-10-09; 96-1000, eff. 7-2-10.)

    (220 ILCS 5/16-111.9)
    Sec. 16-111.9. Rate relief; electricity suppliers. On and after August 14, 2009 (the effective date of Public Act 96-533), any electric utility providing rate relief pursuant to Section 16-111.5A of this Act shall not deem any residential or non-residential customer to be ineligible to receive that relief solely based upon that customer's purchase of electricity from a supplier other than that electric utility at the time the rate relief is to be credited to that customer. Nothing in this Section shall entitle customers of an electric utility that had been previously deemed ineligible prior to August 14, 2009 (the effective date of Public Act 96-533) to become eligible for rate relief credits.
(Source: P.A. 96-533, eff. 8-14-09; 96-1000, eff. 7-2-10.)

    (220 ILCS 5/16-112)
    Sec. 16-112. Determination of market value.
    (a) The market value to be used in the calculation of transition charges as defined in Section 16-102 shall be determined in accordance with either (i) a tariff that has been filed by the electric utility with the Commission pursuant to Article IX of this Act and that provides for a determination of the market value for electric power and energy as a function of an exchange traded or other market traded index, options or futures contract or contracts applicable to the market in which the utility sells, and the customers in its service area buy, electric power and energy, or (ii) in the event no such tariff has been placed into effect for the electric utility, or in the event such tariff does not establish market values for each of the years specified in the neutral fact-finder process described in subsections (b) through (h) of this Section, a tariff incorporating the market values resulting from the neutral fact-finder process set forth in subsections (b) through (h) of this Section.
    (b) Except as provided in subsection (m) of this Section, on or before April 30, 1998, on or before February 28, 1999, and on or before each April 30 from 2000 until 2007, the Commission shall appoint a neutral fact-finder to make the calculations described in subsection (c) of this Section. The neutral fact-finder shall be a member of a national public accounting firm, shall not have served as the neutral fact-finder in the previous year, and shall be selected from a list of candidates provided by a nationally recognized provider of neutral fact-finders that has established rules for maintaining confidentiality. An amount sufficient to pay the fees of the neutral fact-finder shall be appropriated annually from the Public Utility Fund in the State treasury.
    (c) On or before June 1, 1998, on or before April 1, 1999, and on or before each June 1 from 2000 until 2007, or until discontinued in accordance with subsection (m) of this Section, each electric utility and each alternative retail electric supplier shall submit to the neutral fact-finder a summary of (A) all contracts entered into after June 1, 1997 that are for the sale of electric power and energy from a generating facility or facilities located in this State or located in a contiguous State and owned by an electric utility as part of its interconnected operating system and delivery during one or more of the 5 years succeeding the date of submission, and (B) all contracts entered into after June 1, 1997 for purchase and delivery of electric power and energy in or into this State during one or more of the 5 years succeeding the date of submission; provided, however, that such contracts shall not include (i) contracts between the electric utility and an affiliate; (ii) sales, purchases, or deliveries made under rates and tariffs filed with the Commission, except for tariffs filed pursuant to subsection (d) of Section 16-110 and except for special or negotiated rate contracts between an electric utility and a retail customer to the extent that such contracts are for the provision of electric power and energy after the date that the customer becomes eligible for delivery services; and (iii) extensions or amendments to full requirements wholesale contracts existing as of the effective date of this amendatory Act of 1997, provided that such contracts, extensions, or amendments are cost of service regulated by the Federal Energy Regulatory Commission. The summaries shall, at a minimum, identify the date of the contract; the year in which the electric power or energy is to be sold or delivered; the point of delivery; defining characteristics such as the nature of the power transaction (for example, reserve responsibility (firm, non-firm)), length of contract and temporal differences (for example, season, on-peak or off-peak); and the applicable prices stated at the point at which the electric power and energy leaves the electric utility's or alternative retail electric supplier's transmission system, as the case may be, in the case of contracts described in item (A) and at the point at which the electric power and energy enters the electric utility's transmission system in the case of contracts in item (B), provided, that the applicable price shall be stated at the point at which the electric power and energy enters the electric utility's transmission system in the case of electric power and energy generated for delivery within the electric utility's service area. In reporting to the neutral fact-finder the price of power and energy sold under bundled service contracts, electric utilities and alternative retail electric suppliers shall deduct from the contract price the charges for delivery services, including transition charges, applicable to delivery services customers in a utility's service area, and charges for services, if any, other than the provision of power and energy or delivery services. The Commission may adopt orders setting forth requirements governing the form and content of such summaries.
    (d) The neutral fact-finder shall calculate market values for electric power and energy for each electric utility, taking into account the defining characteristics set forth in subsection (c) of this Section; provided, however, that the neutral fact-finder may determine that a particular value is appropriate for more than one electric utility, or for all electric utilities in this State. The neutral fact-finder shall calculate the market values for the next year and, to the extent the summaries include a sufficient number of actual contracts to represent a viable market for the sale and delivery of electric power and energy in subsequent years, for each of the 4 succeeding years.
    (e) In calculating market values for electric power, the neutral fact-finder shall weight contract prices (including any contract price indices) by both the amount of capacity covered by the contract and the number of hours in which capacity is to be provided under the contract in each period of the year, shall take into account all of the defining characteristics set forth in subsection (c) of this Section and shall develop such values as required to represent the different types of market values of electric power.
    (f) The neutral fact-finder shall base calculations of the market values for electric energy on the energy prices stated in the contracts, and where no explicit energy prices or index price basis are stated, on the actual energy costs of the supplier in the corresponding period of the preceding year that would have been applicable to the electric energy provided under the contract. The neutral fact-finder shall develop market values for electric energy and shall take into account the defining characteristics set forth in subsection (c) of this Section, as required to represent the market values of such electric energy.
    (g) If the contracts used by the neutral fact-finder base prices for future years on one or more indices, the neutral fact-finder shall identify such indices in his or her final report, develop a weighting for each index, and calculate a weighted average index. The market values shall be calculated using the weighted average index when the actual values of the component indices are known.
    (h) The neutral fact-finder shall publish a final report on or before July 30 of each year, except that in 1999 the neutral fact finder shall publish the report on or before May 30, setting forth the calculated market values and stating the basis for such calculations. The final report shall not, however, disclose any proprietary or confidential data.
    (i) The market values calculated by the neutral fact-finder shall not be admissible in any proceeding for any purpose other than the calculation of transition charges or calculation of the price for the power purchase options provided pursuant to subsection (b) and (c) of Section 16-110.
    (j) The Commission shall have access to all contracts described in subsection (c) of this Section and shall perform such audits as it and the neutral fact-finder deem necessary to insure the accuracy of the summaries submitted to the neutral fact-finder. The summaries described in subsection (c) of this Section and each contract shall be accorded confidential and proprietary treatment and their review shall be subject to the provisions of Sections 4-404 and 5-108 of this Act, and the contract between the Commission and the neutral fact-finder shall contain provisions obligating the neutral fact-finder to comply with such Sections. The summaries shall not be discoverable by any party in any proceeding absent a compelling demonstration of need.
    (k) In determining the market values to be used for the various customer classes in calculating transition charges as defined in Section 16-102 or for the power purchase options set forth in Section 16-110, an electric utility shall apply the market values that are determined as set forth in subsection (a) to the electric power and energy that would have been used to serve the delivery services customers' electric power and energy requirements, based on the usage specified in Section 16-102 and taking into account the daily, monthly, annual and other relevant characteristics of the customers' demands on the electric utility's system.
    (l) In calculating a lump sum transition charge payment for the purposes of subsection (h) of Section 16-108, the electric utility shall use the market values that were determined as provided in its tariff, or if such market values have not been determined for the full period of time covered by such lump sum calculation, such other basis as is stated in the electric utility's tariff filed pursuant to Section 16-108.
    (m) The Commission may approve or reject, or propose modifications to, any tariff providing for the determination of market value that has been proposed by an electric utility pursuant to subsection (a) of this Section, but shall not have the power to otherwise order the electric utility to implement a modified tariff or to place into effect any tariff for the determination of market value other than one incorporating the neutral fact-finder procedure set forth in this Section. Provided, however, that if each electric utility serving at least 300,000 customers has placed into effect a tariff that provides for a determination of market value as a function of an exchange traded or other market traded index, options or futures contract or contracts, then the Commission can require any other electric utilities to file such a tariff, and can terminate the neutral fact-finder procedure for the periods covered by such tariffs.
    (n) To the extent that the summaries list a sufficient number of actual contracts to represent a viable market and market values can be determined for more than one year, the electric utility shall offer customers that are obligated to pay transition charges contracts that establish for one or more years, up to a maximum of the lesser of 5 years or the remaining number of years until December 31, 2008, the market value or values to be used in calculating the customer's transition charges in such years and for which market value determinations have been made. The electric utility may require any customer to give up to one year notice prior to entering into a one or 2 year contract pursuant to this subsection, up to 2 years notice for a 3 year contract, and up to 3 years notice for a 4 or 5 year contract. Contracts of one or 2 years duration shall incorporate the market values that were determined as provided in this Section in the year in which the notice is required to be given. Contracts of more than 2 years duration shall incorporate the market values that are determined in the year prior to the first year in which the electric utility will collect transition charges from the customer under the contract. The electric utility shall also allow customers to select, at the time that a customer gives its notice, an option to revoke the notice within 30 days following the determination of the market values that will apply under the contract requested by the customer, and may charge customers a fee for such option that is set forth in a tariff filed pursuant to Article IX and that is adequate to allow the electric utility to recover its transactional costs and compensate it based on the cost that would be incurred to purchase an option to cover the risk associated with the customer's option to revoke. The electric utility shall not be required to offer customers a contract under this paragraph for any year for which no determination of market value has been made either by the neutral fact-finder or pursuant to a tariff filed by the electric utility.
    (o) An electric utility shall have no obligation to provide electric power or energy as a tariffed service for the electric power and energy requirements placed on delivery service by any customer that has entered into a contract pursuant to subsection (n) of this Section and has not purchased and exercised an option to revoke, during the term of the contract. A customer that has purchased and exercised an option to revoke under this subsection shall remain eligible to receive any tariffed service for which it would otherwise be eligible.
(Source: P.A. 90-561, eff. 12-16-97.)

    (220 ILCS 5/16-113)
    Sec. 16-113. Declaration of service as a competitive service.
    (a) An electric utility may, by petition, request the Commission to declare a tariffed service that is provided by the electric utility, and that has not otherwise been declared to be competitive, to be a competitive service. The electric utility shall give notice of its petition to the public in the same manner that public notice is provided for proposed general increases in rates for tariffed services, in accordance with rules and regulations prescribed by the Commission. The Commission shall hold a hearing and shall declare the class of tariffed service to be a competitive service within the electric utility's service area, only after the electric utility demonstrates that at least 33% of the customers in the electric utility's service area that are eligible to take the class of tariffed service instead take service from alternative retail electric suppliers, as defined in Section 16-102, and that at least 3 alternative retail electric suppliers provide service that is comparable to the class of tariffed service to those customers in the electric utility's service area that do not take service from the electric utility. The Commission shall make its determination and issue its final order declaring or refusing to declare the service to be a competitive service within 180 days following the date that the petition is filed.
    (b) Except as otherwise set forth in this Section, any customer except a customer identified in subsection (c) of Section 16-103 who is taking a tariffed service that is declared to be a competitive service pursuant to subsection (a) of this Section shall be entitled to continue to take the service from the electric utility on a tariffed basis for a period of 3 years following the date that the service is declared competitive, or such other period as is stated in the electric utility's tariff pursuant to Section 16-110. This subsection shall not require the electric utility to offer or provide on a tariffed basis any service to any customer (except those customers identified in subsection (c) of Section 16-103) that was not taking such service on a tariffed basis on the date the service was declared to be competitive.
    Customers of an electric utility that on December 31, 2005 provided electric service to at least 2,000,000 customers in Illinois and (i) whose service is declared to be a competitive service pursuant to subsection (f) of this Section, (ii) that have peak demand of 400 kilowatts and above, and (iii) that were taking that service from the utility on the effective date of this amendatory Act through fixed-price bundled service tariffs, shall be entitled to continue to take the service from the electric utility on a tariffed basis through the end of the May 2008 billing period. Customers of an electric utility that on December 31, 2005 provided electric service to at least 2,000,000 customers in Illinois and (i) whose service is declared to be a competitive service pursuant to subsection (g) of this Section, (ii) that have peak demand of 100 kilowatts and above but less than 400 kilowatts, and (iii) that were taking that service from the utility on the effective date of this amendatory Act through fixed-price bundled service tariffs, shall be entitled to continue to take the service from the electric utility on a tariffed basis through the end of the May 2010 billing period.
    Customers of an electric utility that on December 31, 2005 provided electric service to 2,000,000 or fewer customers but more than 100,000 customers in Illinois and (i) whose service is declared to be a competitive service pursuant to subsection (f) of this Section, (ii) that have peak demand of one megawatt and above, and (iii) that were taking that service from the utility on the effective date of this amendatory Act through fixed-price bundled service tariffs, shall be entitled to continue to take the service from the electric utility on a tariffed basis through the end of May 2008. Customers of an electric utility that on December 31, 2005 provided electric service to 2,000,000 or fewer customers but more than 100,000 customers in the State of Illinois and (i) whose service is declared to be a competitive service pursuant to subsection (f) of this Section, (ii) that have peak demand of 400 kilowatts and above but less than one megawatt, and (iii) that were taking that service from the utility on the effective date of this amendatory Act through fixed-price bundled service tariffs, shall be entitled to continue to take the service from the electric utility on a tariffed basis through the end of May 2010.
    (c) If the Commission denies a petition to declare a service to be a competitive service, or determines in a separate proceeding that a service is not competitive based on the criteria set forth in subsection (a), the electric utility may file a new petition no earlier than 6 months following the date of the Commission's order, requesting, on the basis of additional or different facts and circumstances, that the service be declared to be a competitive service.
    (d) The Commission shall not deny a petition to declare a service to be a competitive service, and shall not find that a service is not a competitive service, on the grounds that it has previously denied the petition of another electric utility to declare the same or a similar service to be a competitive service or has previously determined that the same or a similar service provided by another electric utility is not a competitive service.
    (e) An electric utility may declare a service, other than delivery services or the provision of electric power or energy, to be competitive by filing with the Commission at least 14 days prior to the date on which the service is to become competitive a notice describing the service that is being declared competitive and the date on which it will become competitive; provided, that any customer who is taking a tariffed service that is declared to be a competitive service pursuant to this subsection (e) shall be entitled to continue to take the service from the electric utility on a tariffed basis until the electric utility files, and the Commission grants, a petition to declare the service competitive in accordance with subsection (a) of this Section. The Commission shall be authorized to find and order, after notice and hearing in a subsequent proceeding initiated by the Commission, that any service declared to be competitive pursuant to this subsection (e) is not competitive in accordance with the criteria set forth in subsection (a) of this Section.
    (f) As of the effective date of this amendatory Act, the provision of electric power and energy, whether through fixed-price bundled service tariffs or otherwise, to those retail customers with peak demands of 400 kilowatts and above that are served by an electric utility that on December 31, 2005 served more than 100,000 customers in its service territory in Illinois shall be deemed to be, and is declared to be, a competitive service.
    (g) An electric utility that provided electric service to at least 100,000 customers in its service territory in Illinois as of December 31, 2005 may seek to declare the provision of electric power and energy, whether through fixed-price bundled service tariffs or otherwise, to those retail customers with peak demand of 100 kilowatts and above but less than 400 kilowatts to be competitive by filing with the Commission at least 60 days prior to the date on which the service is to become competitive a petition with attached analyses demonstrating that at least 33% of those customers in the electric utility's service area that are eligible to take the class of tariffed service instead take service from alternative retail electric suppliers, as defined in Section 16-102, and that at least 3 alternative retail electric suppliers provide service that is comparable to that tariffed service to those customers in the electric utility's service area that do not take service from the electric utility. The electric utility shall give notice of its petition to the public in the same manner that public notice is provided for proposed general increases in rates for tariffed services, in accordance with rules and regulations prescribed by the Commission. Within 14 days following filing of the petition, any person may file a detailed objection with the Commission contesting the analyses submitted by the electric utility with its petition. All objections to the electric utility's petition shall be specific, supported by data or other detailed analyses, and limited to whether the electric utility has met the standard set forth in this subsection (g). The electric utility may file a response to any objections to its petition within 7 days after the deadline for objections. The Commission shall declare the provision of electric power and energy by the electric utility to those retail customers with peak demand of 100 kilowatts and above but less than 400 kilowatts to be a competitive service within 30 days after the filing of the petition if it finds that the electric utility has met the standard set forth in this subsection (g). If, however, the Commission finds that there are material issues of disputed fact, it may require the parties to submit additional information, including through additional filings or as part of an evidentiary hearing. If the Commission has required the parties to submit additional information, it shall issue an order within 60 days after the filing of the petition stating whether the provision of electric power and energy by the utility to those retail customers with peak demand of 100 kilowatts and above but less than 400 kilowatts has been declared to be a competitive service.
    (h) Until July 1, 2012, no electric utility that on December 31, 2005 provided electric service to at least 100,000 customers in its service territory in Illinois may seek to declare the class of tariffed service for residential customers and those non-residential customers with peak demand of less than 100 kilowatts to be a competitive service.
(Source: P.A. 95-481, eff. 8-28-07.)

    (220 ILCS 5/16-114)
    Sec. 16-114. Recovery of decommissioning charges. On or before April 1, 1999, each electric utility owning an interest in, or having responsibility as a matter of contract or statute for decommissioning costs as defined in Section 8-508.1 of, one or more nuclear power plants shall file with the Commission a tariff or tariffs conforming to the provisions of Section 9-201.5 of this Act, to be applicable to each and every kilowatt-hour of electricity delivered or sold at retail in the electric utility's service area, including, but not limited to, sales by the electric utility to tariffed services retail customers, sales by the electric utility to retail customers pursuant to special contracts or other negotiated arrangements, sales by alternative retail electric suppliers, and sales by an electric utility other than the electric utility in whose service area the retail customer is located; provided, however, that for a user that obtained electric power and energy from its own cogeneration or self-generation facilities on or before January 1, 1997, and subsequently takes services from an alternative retail electric supplier or an electric utility other than the electric utility in whose service area the user is located for any portion of its electric power and energy requirements formerly obtained from those facilities, the tariff required by this Section shall not be applicable in any year to that portion of the user's electric power and energy requirements formerly obtained from those facilities, provided that for the purposes of this Section, such portion shall not exceed the average number of kilowatt-hours per year obtained from the cogeneration or self-generation facilities during the 3 years prior to the date on which the user became eligible for delivery services.
    The Commission shall determine whether the tariff meets the requirements of Sections 9-201 and 9-201.5 and of this Section, and shall permit the electric utility's tariff together with any modifications made after hearing to become effective no later than October 1, 1999. In making its determination, the Commission shall retain the authority it possessed prior to the effective date of this amendatory Act of 1997 to make jurisdictional allocations of decommissioning expense recovery. The tariff filed pursuant to this Section shall be applicable to any user taking some or all of its electric power and energy requirements from an alternative retail electric supplier or from an electric utility other than the electric utility in whose service area the user is located on and after the date that the user becomes eligible for delivery services in accordance with Section 16-104. If the electric utility has in effect as of the effective date of this amendatory Act of 1997 a decommissioning rate as defined in Section 9-201.5 conforming to the requirements of that Section, the tariff or tariffs required by this Section shall if the electric utility requests be consistent with its decommissioning rate that is already in effect; provided, that the tariff or tariffs filed pursuant to this Section shall provide for the removal from base rates of any decommissioning costs that are included in the electric utility's base rates and their inclusion in the tariff or tariffs required by this Section. The tariff required by this Section shall be included by the Commission in the reviews required by subsection (d) of Section 9-201.5.
(Source: P.A. 90-561, eff. 12-16-97.)

    (220 ILCS 5/16-114.1)
    Sec. 16-114.1. Recovery of decommissioning costs in connection with nuclear power plant sale agreement.
    (a) An electric utility owning a single-unit nuclear power plant located in this State which enters into an agreement to sell the nuclear power plant and as part of such agreement agrees: (i) to make contributions to a tax-qualified decommissioning trust or non-tax qualified decommissioning trust, or both, as defined in Section 8-508.1 for the nuclear power plant, in specified amounts or for a specified period of time, after the sale is consummated, or (ii) to purchase an insurance instrument which provides for the payment of all or a specified amount of the decommissioning costs of the nuclear power plant, shall be entitled, in the case of item (i), to maintain such decommissioning trusts for the purpose of receiving such contributions after the consummation of the sale, to implement revisions to its decommissioning rate in accordance with subsection (b) of this Section, and to transfer such decommissioning trusts, or the balance in the trusts, to the buyer of the nuclear power plant in accordance with the agreement of sale, and in the case of item (ii), to implement revisions to its decommissioning rate in accordance with subsection (c) of this Section.
    (b) An electric utility entering into an agreement of sale described in subsection (a)(i) of this Section shall be entitled to file a petition with the Commission for entry of an order authorizing the electric utility (i) to amortize its liability for decommissioning costs pursuant to the agreement of sale over the period of time in which the electric utility is required by such agreement to make additional contributions to the tax-qualified decommissioning trust, the non-tax qualified decommissioning trust, or both, and (ii) to revise its decommissioning rate to a level that will recover, over the time period specified in the agreement of sale, an annual amount equal to the electric utility's annual contributions to the decommissioning trusts which are required by the agreement of sale multiplied by the percentage of the output of the nuclear power plant which the agreement of sale obligates the electric utility to purchase in each such year.
    (c) An electric utility entering into an agreement of sale described in subsection (a)(ii) shall be entitled to file a petition with the Commission for entry of an order authorizing the electric utility to revise its decommissioning rate to a level that will recover, over 5 years, the electric utility's cost of purchasing the insurance instrument multiplied by the percentage of the output of the nuclear power plant which the agreement of sale obligates the electric utility to purchase in each such year.
    (d) An electric utility's petition pursuant to subsection (b) or subsection (c) shall state the percentage of the output of the nuclear power plant which the agreement of sale obligates the electric utility to purchase from the new owner of the nuclear power plant in each of the years for which the electric utility is seeking to implement a revised decommissioning rate. The electric utility's petition shall also state that the electric utility agrees, as conditions of the Commission's order and the implementation of the revised decommissioning rate, (i) to file revisions, pursuant to Section 16-111(f), to its base rate tariffs applicable to retail customers subject to the electric utility's decommissioning rate reducing such tariffs, and (ii) to file revisions to its transition charge tariffs applicable to retail customers subject to the electric utility's decommissioning rate incorporating a credit into the calculation of the electric utility's transition charges in accordance with this subsection. The reduction and the credit shall be in an amount per kilowatt-hour of electricity sold or delivered to retail customers equal to (i) the electric utility's decommissioning rate authorized by the Commission's order in accordance with subsection (b)(ii) or (c), as applicable, less (ii) the product of the electric utility's decommissioning rate in effect immediately prior to the agreement of sale multiplied by the percentage of the output of the nuclear power plant which the agreement of sale obligates the electric utility to purchase from the new owner of the nuclear power plant. The Commission shall issue an order granting the petition within 30 days after the petition is filed. The Commission's order shall state the aggregate total amount which the order is authorizing the electric utility to collect through its decommissioning rate. The Commission's order shall state that the effectiveness of the revisions to the electric utility's decommissioning rate shall be conditioned on the filing by the electric utility of the revisions reducing its base rate tariffs and providing for credits to its transition charge tariffs as specified in this subsection. Upon completion of the collection of the total amount which the Commission's order authorizes the electric utility to collect through its decommissioning rate, the electric utility shall not be entitled to collect any further amounts of decommissioning costs for its nuclear power plant through a decommissioning rate. Nothing in this Section shall be construed to permit an increase in the overall tariffed rates and charges paid by the electric utility's customers.
    (e) In addition to the uses of the proceeds of the sale and issuance of transitional funding instruments authorized by Section 18-103(d)(1), an electric utility which has entered into an agreement to sell a nuclear power plant may use the proceeds from the sale and issuance of transitional funding instruments to make contributions, or to reimburse itself for contributions which the electric utility has made, to decommissioning trusts in accordance with the agreement of sale, in an amount not to exceed 20% of the aggregate principal amount of transitional funding instruments which the electric utility was authorized to cause to have issued pursuant to Section 18-103(d)(6), including for purposes of this calculation the amount of any transitional funding instruments which the electric utility caused to be issued prior to the date of this amendatory Act of 1999. The use of proceeds authorized by this subsection shall not be subject to Section 18-103(d)(1)(B) and shall not be considered in determining if the percentage limitations on the use of proceeds set forth in the proviso following Section 18-103(d)(1)(E) have been complied with.
    (f) None of the authorizations permitted by this Section may be exercised if the sale of the nuclear power plant is disapproved by the Commission.
(Source: P.A. 91-50, eff. 6-30-99.)

    (220 ILCS 5/16-115)
    Sec. 16-115. Certification of alternative retail electric suppliers.
    (a) Any alternative retail electric supplier must obtain a certificate of service authority from the Commission in accordance with this Section before serving any retail customer or other user located in this State. An alternative retail electric supplier may request, and the Commission may grant, a certificate of service authority for the entire State or for a specified geographic area of the State.
    (b) An alternative retail electric supplier seeking a certificate of service authority shall file with the Commission a verified application containing information showing that the applicant meets the requirements of this Section. The alternative retail electric supplier shall publish notice of its application in the official State newspaper within 10 days following the date of its filing. No later than 45 days after the application is properly filed with the Commission, and such notice is published, the Commission shall issue its order granting or denying the application.
    (c) An application for a certificate of service authority shall identify the area or areas in which the applicant intends to offer service and the types of services it intends to offer. Applicants that seek to serve residential or small commercial retail customers within a geographic area that is smaller than an electric utility's service area shall submit evidence demonstrating that the designation of this smaller area does not violate Section 16-115A. An applicant that seeks to serve residential or small commercial retail customers may state in its application for certification any limitations that will be imposed on the number of customers or maximum load to be served.
    (d) The Commission shall grant the application for a certificate of service authority if it makes the findings set forth in this subsection based on the verified application and such other information as the applicant may submit:
        (1) That the applicant possesses sufficient

    
technical, financial and managerial resources and abilities to provide the service for which it seeks a certificate of service authority. In determining the level of technical, financial and managerial resources and abilities which the applicant must demonstrate, the Commission shall consider (i) the characteristics, including the size and financial sophistication, of the customers that the applicant seeks to serve, and (ii) whether the applicant seeks to provide electric power and energy using property, plant and equipment which it owns, controls or operates;
        (2) That the applicant will comply with all
    
applicable federal, State, regional and industry rules, policies, practices and procedures for the use, operation, and maintenance of the safety, integrity and reliability, of the interconnected electric transmission system;
        (3) That the applicant will only provide service to
    
retail customers in an electric utility's service area that are eligible to take delivery services under this Act;
        (4) That the applicant will comply with such
    
informational or reporting requirements as the Commission may by rule establish and provide the information required by Section 16-112. Any data related to contracts for the purchase and sale of electric power and energy shall be made available for review by the Staff of the Commission on a confidential and proprietary basis and only to the extent and for the purposes which the Commission determines are reasonably necessary in order to carry out the purposes of this Act;
        (5) That the applicant will procure renewable energy
    
resources in accordance with Section 16-115D of this Act, and will source electricity from clean coal facilities, as defined in Section 1-10 of the Illinois Power Agency Act, in amounts at least equal to the percentages set forth in subsections (c) and (d) of Section 1-75 of the Illinois Power Agency Act. For purposes of this Section:
            (i) (Blank);
            (ii) (Blank);
            (iii) the required sourcing of electricity
        
generated by clean coal facilities, other than the initial clean coal facility, shall be limited to the amount of electricity that can be procured or sourced at a price at or below the benchmarks approved by the Commission each year in accordance with item (1) of subsection (c) and items (1) and (5) of subsection (d) of Section 1-75 of the Illinois Power Agency Act;
            (iv) all alternative retail electric suppliers
        
shall execute a sourcing agreement to source electricity from the initial clean coal facility, on the terms set forth in paragraphs (3) and (4) of subsection (d) of Section 1-75 of the Illinois Power Agency Act, except that in lieu of the requirements in subparagraphs (A)(v), (B)(i), (C)(v), and (C)(vi) of paragraph (3) of that subsection (d), the applicant shall execute one or more of the following:
                (1) if the sourcing agreement is a power
            
purchase agreement, a contract with the initial clean coal facility to purchase in each hour an amount of electricity equal to all clean coal energy made available from the initial clean coal facility during such hour, which the utilities are not required to procure under the terms of subsection (d) of Section 1-75 of the Illinois Power Agency Act, multiplied by a fraction, the numerator of which is the alternative retail electric supplier's retail market sales of electricity (expressed in kilowatthours sold) in the State during the prior calendar month and the denominator of which is the total sales of electricity (expressed in kilowatthours sold) in the State by alternative retail electric suppliers during such prior month that are subject to the requirements of this paragraph (5) of subsection (d) of this Section and subsection (d) of Section 1-75 of the Illinois Power Agency Act plus the total sales of electricity (expressed in kilowatthours sold) by utilities outside of their service areas during such prior month, pursuant to subsection (c) of Section 16-116 of this Act; or
                (2) if the sourcing agreement is a contract
            
for differences, a contract with the initial clean coal facility in each hour with respect to an amount of electricity equal to all clean coal energy made available from the initial clean coal facility during such hour, which the utilities are not required to procure under the terms of subsection (d) of Section 1-75 of the Illinois Power Agency Act, multiplied by a fraction, the numerator of which is the alternative retail electric supplier's retail market sales of electricity (expressed in kilowatthours sold) in the State during the prior calendar month and the denominator of which is the total sales of electricity (expressed in kilowatthours sold) in the State by alternative retail electric suppliers during such prior month that are subject to the requirements of this paragraph (5) of subsection (d) of this Section and subsection (d) of Section 1-75 of the Illinois Power Agency Act plus the total sales of electricity (expressed in kilowatthours sold) by utilities outside of their service areas during such prior month, pursuant to subsection (c) of Section 16-116 of this Act;
            (v) if, in any year after the first year of
        
commercial operation, the owner of the clean coal facility fails to demonstrate to the Commission that the initial clean coal facility captured and sequestered at least 50% of the total carbon emissions that the facility would otherwise emit or that sequestration of emissions from prior years has failed, resulting in the release of carbon into the atmosphere, the owner of the facility must offset excess emissions. Any such carbon offsets must be permanent, additional, verifiable, real, located within the State of Illinois, and legally and practicably enforceable. The costs of any such offsets that are not recoverable shall not exceed $15 million in any given year. No costs of any such purchases of carbon offsets may be recovered from an alternative retail electric supplier or its customers. All carbon offsets purchased for this purpose and any carbon emission credits associated with sequestration of carbon from the facility must be permanently retired. The initial clean coal facility shall not forfeit its designation as a clean coal facility if the facility fails to fully comply with the applicable carbon sequestration requirements in any given year, provided the requisite offsets are purchased. However, the Attorney General, on behalf of the People of the State of Illinois, may specifically enforce the facility's sequestration requirement and the other terms of this contract provision. Compliance with the sequestration requirements and offset purchase requirements that apply to the initial clean coal facility shall be reviewed annually by an independent expert retained by the owner of the initial clean coal facility, with the advance written approval of the Attorney General;
            (vi) The Commission shall, after notice and
        
hearing, revoke the certification of any alternative retail electric supplier that fails to execute a sourcing agreement with the initial clean coal facility as required by item (5) of subsection (d) of this Section. The sourcing agreements with this initial clean coal facility shall be subject to both approval of the initial clean coal facility by the General Assembly and satisfaction of the requirements of item (4) of subsection (d) of Section 1-75 of the Illinois Power Agency Act, and shall be executed within 90 days after any such approval by the General Assembly. The Commission shall not accept an application for certification from an alternative retail electric supplier that has lost certification under this subsection (d), or any corporate affiliate thereof, for at least one year from the date of revocation;
        (6) With respect to an applicant that seeks to serve
    
residential or small commercial retail customers, that the area to be served by the applicant and any limitations it proposes on the number of customers or maximum amount of load to be served meet the provisions of Section 16-115A, provided, that the Commission can extend the time for considering such a certificate request by up to 90 days, and can schedule hearings on such a request;
        (7) That the applicant meets the requirements of
    
subsection (a) of Section 16-128; and
        (8) That the applicant will comply with all other
    
applicable laws and regulations.
    (d-5) (Blank).
    (e) A retail customer that owns a cogeneration or self-generation facility and that seeks certification only to provide electric power and energy from such facility to retail customers at separate locations which customers are both (i) owned by, or a subsidiary or other corporate affiliate of, such applicant and (ii) eligible for delivery services, shall be granted a certificate of service authority upon filing an application and notifying the Commission that it has entered into an agreement with the relevant electric utilities pursuant to Section 16-118. Provided, however, that if the retail customer owning such cogeneration or self-generation facility would not be charged a transition charge due to the exemption provided under subsection (f) of Section 16-108 prior to the certification, and the retail customers at separate locations are taking delivery services in conjunction with purchasing power and energy from the facility, the retail customer on whose premises the facility is located shall not thereafter be required to pay transition charges on the power and energy that such retail customer takes from the facility.
    (f) The Commission shall have the authority to promulgate rules and regulations to carry out the provisions of this Section. On or before May 1, 1999, the Commission shall adopt a rule or rules applicable to the certification of those alternative retail electric suppliers that seek to serve only nonresidential retail customers with maximum electrical demands of one megawatt or more which shall provide for (i) expedited and streamlined procedures for certification of such alternative retail electric suppliers and (ii) specific criteria which, if met by any such alternative retail electric supplier, shall constitute the demonstration of technical, financial and managerial resources and abilities to provide service required by subsection (d) (1) of this Section, such as a requirement to post a bond or letter of credit, from a responsible surety or financial institution, of sufficient size for the nature and scope of the services to be provided; demonstration of adequate insurance for the scope and nature of the services to be provided; and experience in providing similar services in other jurisdictions.
(Source: P.A. 95-130, eff. 1-1-08; 95-1027, eff. 6-1-09; 96-159, eff. 8-10-09.)

    (220 ILCS 5/16-115A)
    Sec. 16-115A. Obligations of alternative retail electric suppliers.
    (a) An alternative retail electric supplier shall:
        (i) comply with the requirements imposed on public

    
utilities by Sections 8-201 through 8-207, 8-301, 8-505 and 8-507 of this Act, to the extent that these Sections have application to the services being offered by the alternative retail electric supplier; and
        (ii) continue to comply with the requirements for
    
certification stated in subsection (d) of Section 16-115.
    (b) An alternative retail electric supplier shall obtain verifiable authorization from a customer, in a form or manner approved by the Commission consistent with Section 2EE of the Consumer Fraud and Deceptive Business Practices Act, before the customer is switched from another supplier.
    (c) No alternative retail electric supplier, or electric utility other than the electric utility in whose service area a customer is located, shall (i) enter into or employ any arrangements which have the effect of preventing a retail customer with a maximum electrical demand of less than one megawatt from having access to the services of the electric utility in whose service area the customer is located or (ii) charge retail customers for such access. This subsection shall not be construed to prevent an arms-length agreement between a supplier and a retail customer that sets a term of service, notice period for terminating service and provisions governing early termination through a tariff or contract as allowed by Section 16-119.
    (d) An alternative retail electric supplier that is certified to serve residential or small commercial retail customers shall not:
        (1) deny service to a customer or group of customers
    
nor establish any differences as to prices, terms, conditions, services, products, facilities, or in any other respect, whereby such denial or differences are based upon race, gender or income.
        (2) deny service to a customer or group of customers
    
based on locality nor establish any unreasonable difference as to prices, terms, conditions, services, products, or facilities as between localities.
    (e) An alternative retail electric supplier shall comply with the following requirements with respect to the marketing, offering and provision of products or services to residential and small commercial retail customers:
        (i) Any marketing materials which make statements
    
concerning prices, terms and conditions of service shall contain information that adequately discloses the prices, terms and conditions of the products or services that the alternative retail electric supplier is offering or selling to the customer.
        (ii) Before any customer is switched from another
    
supplier, the alternative retail electric supplier shall give the customer written information that adequately discloses, in plain language, the prices, terms and conditions of the products and services being offered and sold to the customer.
        (iii) An alternative retail electric supplier shall
    
provide documentation to the Commission and to customers that substantiates any claims made by the alternative retail electric supplier regarding the technologies and fuel types used to generate the electricity offered or sold to customers.
        (iv) The alternative retail electric supplier shall
    
provide to the customer (1) itemized billing statements that describe the products and services provided to the customer and their prices, and (2) an additional statement, at least annually, that adequately discloses the average monthly prices, and the terms and conditions, of the products and services sold to the customer.
    (f) An alternative retail electric supplier may limit the overall size or availability of a service offering by specifying one or more of the following: a maximum number of customers, maximum amount of electric load to be served, time period during which the offering will be available, or other comparable limitation, but not including the geographic locations of customers within the area which the alternative retail electric supplier is certificated to serve. The alternative retail electric supplier shall file the terms and conditions of such service offering including the applicable limitations with the Commission prior to making the service offering available to customers.
    (g) Nothing in this Section shall be construed as preventing an alternative retail electric supplier, which is an affiliate of, or which contracts with, (i) an industry or trade organization or association, (ii) a membership organization or association that exists for a purpose other than the purchase of electricity, or (iii) another organization that meets criteria established in a rule adopted by the Commission, from offering through the organization or association services at prices, terms and conditions that are available solely to the members of the organization or association.
(Source: P.A. 90-561, eff. 12-16-97.)

    (220 ILCS 5/16-115B)
    Sec. 16-115B. Commission oversight of services provided by alternative retail electric suppliers.
    (a) The Commission shall have jurisdiction in accordance with the provisions of Article X of this Act to entertain and dispose of any complaint against any alternative retail electric supplier alleging (i) that the alternative retail electric supplier has violated or is in nonconformance with any applicable provisions of Section 16-115 through Section 16-115A; (ii) that an alternative retail electric supplier serving retail customers having maximum demands of less than one megawatt has failed to provide service in accordance with the terms of its contract or contracts with such customer or customers; (iii) that the alternative retail electric supplier has violated or is in non-conformance with the delivery services tariff of, or any of its agreements relating to delivery services with, the electric utility, municipal system, or electric cooperative providing delivery services; or (iv) that the alternative retail electric supplier has violated or failed to comply with the requirements of Sections 8-201 through 8-207, 8-301, 8-505, or 8-507 of this Act as made applicable to alternative retail electric suppliers.
    (b) The Commission shall have authority, after notice and hearing held on complaint or on the Commission's own motion:
        (1) To order an alternative retail electric supplier

    
to cease and desist, or correct, any violation of or non-conformance with the provisions of Section 16-115 or 16-115A;
        (2) To impose financial penalties for violations of
    
or non-conformances with the provisions of Section 16-115 or 16-115A, not to exceed (i) $10,000 per occurrence or (ii) $30,000 per day for those violations or non-conformances which continue after the Commission issues a cease and desist order; and
        (3) To alter, modify, revoke or suspend the
    
certificate of service authority of an alternative retail electric supplier for substantial or repeated violations of or non-conformances with the provisions of Section 16-115 or 16-115A.
(Source: P.A. 90-561, eff. 12-16-97.)

    (220 ILCS 5/16-115C)
    Sec. 16-115C. Licensure of agents, brokers, and consultants engaged in the procurement or sale of retail electricity supply for third parties.
    (a) The purpose of this Section is to adopt licensing and code of conduct rules in a competitive retail electricity market to protect Illinois consumers from unfair or deceptive acts or practices and to provide persons acting as agents, brokers, and consultants engaged in the procurement or sale of retail electricity supply for third parties with notice of the illegality of those acts or practices.
    (a-5) All third-party sales representatives engaged in the marketing of retail electricity supply must, prior to the customer signing a contract, disclose that they are not employed by the electric utility operating in the applicable service territory.
    (b) For purposes of this Section, "agents, brokers, and consultants engaged in the procurement or sale of retail electricity supply for third parties" means any person or entity that attempts to procure on behalf of or sell retail electric service to an electric customer in the State. "Agents, brokers, and consultants engaged in the procurement or sale of retail electricity supply for third parties" does not include the Illinois Power Agency or any of its employees, any entity licensed as an alternative retail electric supplier pursuant to 83 Ill. Adm. Code 451 offering retail electric service on its own behalf, any person acting exclusively on behalf of a single alternative retail electric supplier on condition that exclusivity is disclosed to any third party contracted in such agent capacity, any person acting exclusively on behalf of a retail electric supplier on condition that exclusivity is disclosed to any third party contracted in such agent capacity, any person or entity representing a municipal power agency, as defined in Section 11-119.1-3 of the Illinois Municipal Code, or any person or entity that is attempting to procure on behalf of or sell retail electric service to a third party that has aggregate billing demand of all of its affiliated electric service accounts in Illinois of greater than 1,500 kW.
    (c) No person or entity shall act as an agent, broker, or consultant engaged in the procurement or sale of retail electricity supply for third parties unless that person or entity is licensed by the Commission under this Section or is offering services on their own behalf under 83 Ill. Adm. Code 451.
    (d) The Commission shall create requirements for licensure as an agent, broker, or consultant engaged in the procurement or sale of retail electricity supply for third parties, which shall include all of the following criteria:
        (1) Technical competence.
        (2) Managerial competence.
        (3) Financial responsibility, including the posting

    
of an appropriate performance bond.
        (4) Annual reporting requirements.
    (e) Any person or entity required to be licensed under this Section must:
        (1) disclose in plain language in writing to all
    
persons it solicits (i) before July 1, 2011, the total anticipated remuneration to be paid to it by any third party over the period of the proposed underlying customer contract and (ii) on or after July 1, 2011, the total price per kilowatt-hour, and the total anticipated cost, inclusive of all fees or commissions received by the licensee, to be paid by the customer over the period of the proposed underlying customer contract;
        (2) disclose, if applicable, to all customers, prior
    
to the customer signing a contract, the fact that they will be receiving compensation from the supplier;
        (3) not hold itself out as independent or
    
unaffiliated with any supplier, or both, or use words reasonably calculated to give that impression, unless the person offering service under this Section has no contractual relationship with any retail electricity supplier or its affiliates regarding retail electric service in Illinois;
        (4) not utilize false, misleading, materially
    
inaccurate, defamatory, or otherwise deceptive language or materials in the soliciting or providing of its services;
        (5) maintain copies of all marketing materials
    
disseminated to third parties for a period of not less than 3 years;
        (6) not present electricity pricing information in a
    
manner that favors one supplier over another, unless a valid pricing comparison is made utilizing all relevant costs and terms; and
        (7) comply with the requirements of Sections 2EE,
    
2FF, 2GG, and 2HH of the Consumer Fraud and Deceptive Business Practices Act.
    (f) Any person or entity licensed under this Section shall file with the Commission all of the following information no later than March of each year:
        (1) A verified report detailing any and all
    
contractual relationships that it has with certified electricity suppliers in the State regarding retail electric service in Illinois.
        (2) A verified report detailing the distribution of
    
its customers with the various certified electricity suppliers in Illinois during the prior calendar year. A report under this Section shall not be required to contain customer-identifying information.
        A public redacted version of the verified report may
    
be submitted to the Commission along with a proprietary version. The public redacted version may redact from the verified report the name or names of every certified electricity supplier contained in the report to protect against disclosure of competitively sensitive market share information. The information shall be afforded proprietary treatment for 2 years after the date of the filing of the verified report.
        (3) A verified statement of any changes to the
    
original licensure qualifications and notice of continuing compliance with all requirements.
    (g) The Commission shall have jurisdiction over disciplinary proceedings and complaints for violations of this Section. The findings of a violation of this Section by the Commission shall result in a progressive disciplinary scale. For a first violation, the Commission may, in its discretion, suspend the license of the person so disciplined for a period of no less than one month. For a second violation within a 5-year period, the Commission shall suspend the license for the person so disciplined for a period of not less than 6 months. For a third or subsequent violation within a 5-year period, the Commission shall suspend the license of the disciplined person for a period of not less than 2 years.
    (h) This Section shall not apply to a retail customer that operates or manages either directly or indirectly any facilities, equipment, or property used or contemplated to be used to distribute electric power or energy if that retail customer is a political subdivision or public institution of higher education of this State, or any corporation, company, limited liability company, association, joint-stock company or association, firm, partnership, or individual, or their lessees, trusts, or receivers appointed by any court whatsoever that are owned or controlled by the political subdivision, public institution of higher education, or operated by any of its lessees or operating agents.
(Source: P.A. 95-679, eff. 10-11-07; 96-1385, eff. 7-29-10.)

    (220 ILCS 5/16-115D)
    Sec. 16-115D. Renewable portfolio standard for alternative retail electric suppliers and electric utilities operating outside their service territories.
    (a) An alternative retail electric supplier shall be responsible for procuring cost-effective renewable energy resources as required under item (5) of subsection (d) of Section 16-115 of this Act as outlined herein:
        (1) The definition of renewable energy resources

    
contained in Section 1-10 of the Illinois Power Agency Act applies to all renewable energy resources required to be procured by alternative retail electric suppliers.
        (2) The quantity of renewable energy resources shall
    
be measured as a percentage of the actual amount of metered electricity (megawatt-hours) delivered by the alternative retail electric supplier to Illinois retail customers during the 12-month period June 1 through May 31, commencing June 1, 2009, and the comparable 12-month period in each year thereafter except as provided in item (6) of this subsection (a).
        (3) The quantity of renewable energy resources shall
    
be in amounts at least equal to the annual percentages set forth in item (1) of subsection (c) of Section 1-75 of the Illinois Power Agency Act. At least 60% of the renewable energy resources procured pursuant to items (1) through (3) of subsection (b) of this Section shall come from wind generation and, starting June 1, 2015, at least 6% of the renewable energy resources procured pursuant to items (1) through (3) of subsection (b) of this Section shall come from solar photovoltaics. If, in any given year, an alternative retail electric supplier does not purchase at least these levels of renewable energy resources, then the alternative retail electric supplier shall make alternative compliance payments, as described in subsection (d) of this Section.
        (4) The quantity and source of renewable energy
    
resources shall be independently verified through the PJM Environmental Information System Generation Attribute Tracking System (PJM-GATS) or the Midwest Renewable Energy Tracking System (M-RETS), which shall document the location of generation, resource type, month, and year of generation for all qualifying renewable energy resources that an alternative retail electric supplier uses to comply with this Section. No later than June 1, 2009, the Illinois Power Agency shall provide PJM-GATS, M-RETS, and alternative retail electric suppliers with all information necessary to identify resources located in Illinois, within states that adjoin Illinois or within portions of the PJM and MISO footprint in the United States that qualify under the definition of renewable energy resources in Section 1-10 of the Illinois Power Agency Act for compliance with this Section 16-115D. Alternative retail electric suppliers shall not be subject to the requirements in item (3) of subsection (c) of Section 1-75 of the Illinois Power Agency Act.
        (5) All renewable energy credits used to comply with
    
this Section shall be permanently retired.
        (6) The required procurement of renewable energy
    
resources by an alternative retail electric supplier shall apply to all metered electricity delivered to Illinois retail customers by the alternative retail electric supplier pursuant to contracts executed or extended after March 15, 2009.
    (b) An alternative retail electric supplier shall comply with the renewable energy portfolio standards by making an alternative compliance payment, as described in subsection (d) of this Section, to cover at least one-half of the alternative retail electric supplier's compliance obligation and any one or combination of the following means to cover the remainder of the alternative retail electric supplier's compliance obligation:
        (1) Generating electricity using renewable energy
    
resources identified pursuant to item (4) of subsection (a) of this Section.
        (2) Purchasing electricity generated using renewable
    
energy resources identified pursuant to item (4) of subsection (a) of this Section through an energy contract.
        (3) Purchasing renewable energy credits from
    
renewable energy resources identified pursuant to item (4) of subsection (a) of this Section.
        (4) Making an alternative compliance payment as
    
described in subsection (d) of this Section.
    (c) Use of renewable energy credits.
        (1) Renewable energy credits that are not used by an
    
alternative retail electric supplier to comply with a renewable portfolio standard in a compliance year may be banked and carried forward up to 2 12-month compliance periods after the compliance period in which the credit was generated for the purpose of complying with a renewable portfolio standard in those 2 subsequent compliance periods. For the 2009-2010 and 2010-2011 compliance periods, an alternative retail electric supplier may use renewable credits generated after December 31, 2008 and before June 1, 2009 to comply with this Section.
        (2) An alternative retail electric supplier is
    
responsible for demonstrating that a renewable energy credit used to comply with a renewable portfolio standard is derived from a renewable energy resource and that the alternative retail electric supplier has not used, traded, sold, or otherwise transferred the credit.
        (3) The same renewable energy credit may be used by
    
an alternative retail electric supplier to comply with a federal renewable portfolio standard and a renewable portfolio standard established under this Act. An alternative retail electric supplier that uses a renewable energy credit to comply with a renewable portfolio standard imposed by any other state may not use the same credit to comply with a renewable portfolio standard established under this Act.
    (d) Alternative compliance payments.
        (1) The Commission shall establish and post on its
    
website, within 5 business days after entering an order approving a procurement plan pursuant to Section 1-75 of the Illinois Power Agency Act, maximum alternative compliance payment rates, expressed on a per kilowatt-hour basis, that will be applicable in the first compliance period following the plan approval. A separate maximum alternative compliance payment rate shall be established for the service territory of each electric utility that is subject to subsection (c) of Section 1-75 of the Illinois Power Agency Act. Each maximum alternative compliance payment rate shall be equal to the maximum allowable annual estimated average net increase due to the costs of the utility's purchase of renewable energy resources included in the amounts paid by eligible retail customers in connection with electric service, as described in item (2) of subsection (c) of Section 1-75 of the Illinois Power Agency Act for the compliance period, and as established in the approved procurement plan. Following each procurement event through which renewable energy resources are purchased for one or more of these utilities for the compliance period, the Commission shall establish and post on its website estimates of the alternative compliance payment rates, expressed on a per kilowatt-hour basis, that shall apply for that compliance period. Posting of the estimates shall occur no later than 10 business days following the procurement event, however, the Commission shall not be required to establish and post such estimates more often than once per calendar month. By July 1 of each year, the Commission shall establish and post on its website the actual alternative compliance payment rates for the preceding compliance year. For compliance years beginning prior to June 1, 2014, each alternative compliance payment rate shall be equal to the total amount of dollars that the utility contracted to spend on renewable resources, excepting the additional incremental cost attributable to solar resources, for the compliance period divided by the forecasted load of eligible retail customers, at the customers' meters, as previously established in the Commission-approved procurement plan for that compliance year. For compliance years commencing on or after June 1, 2014, each alternative compliance payment rate shall be equal to the total amount of dollars that the utility contracted to spend on all renewable resources for the compliance period divided by the forecasted load of eligible retail customers, at the customers' meters, as previously established in the Commission-approved procurement plan for that compliance year. The actual alternative compliance payment rates may not exceed the maximum alternative compliance payment rates established for the compliance period. For purposes of this subsection (d), the term "eligible retail customers" has the same meaning as found in Section 16-111.5 of this Act.
        (2) In any given compliance year, an alternative
    
retail electric supplier may elect to use alternative compliance payments to comply with all or a part of the applicable renewable portfolio standard. In the event that an alternative retail electric supplier elects to make alternative compliance payments to comply with all or a part of the applicable renewable portfolio standard, such payments shall be made by September 1, 2010 for the period of June 1, 2009 to May 1, 2010 and by September 1 of each year thereafter for the subsequent compliance period, in the manner and form as determined by the Commission. Any election by an alternative retail electric supplier to use alternative compliance payments is subject to review by the Commission under subsection (e) of this Section.
        (3) An alternative retail electric supplier's
    
alternative compliance payments shall be computed separately for each electric utility's service territory within which the alternative retail electric supplier provided retail service during the compliance period, provided that the electric utility was subject to subsection (c) of Section 1-75 of the Illinois Power Agency Act. For each service territory, the alternative retail electric supplier's alternative compliance payment shall be equal to (i) the actual alternative compliance payment rate established in item (1) of this subsection (d), multiplied by (ii) the actual amount of metered electricity delivered by the alternative retail electric supplier to retail customers within the service territory during the compliance period, multiplied by (iii) the result of one minus the ratios of the quantity of renewable energy resources used by the alternative retail electric supplier to comply with the requirements of this Section within the service territory to the product of the percentage of renewable energy resources required under item (3) of subsection (a) of this Section and the actual amount of metered electricity delivered by the alternative retail electric supplier to retail customers within the service territory during the compliance period.
        (4) All alternative compliance payments by
    
alternative retail electric suppliers shall be deposited in the Illinois Power Agency Renewable Energy Resources Fund and used to purchase renewable energy credits, in accordance with Section 1-56 of the Illinois Power Agency Act. Beginning April 1, 2012 and by April 1 of each year thereafter, the Illinois Power Agency shall submit an annual report to the General Assembly, the Commission, and alternative retail electric suppliers that shall include, but not be limited to:
            (A) the total amount of alternative compliance
        
payments received in aggregate from alternative retail electric suppliers by planning year for all previous planning years in which the alternative compliance payment was in effect;
            (B) the amount of those payments utilized to
        
purchased renewable energy credits itemized by the date of each procurement in which the payments were utilized; and
            (C) the unused and remaining balance in the
        
Agency Renewable Energy Resources Fund attributable to those payments.
        (5) The Commission, in consultation with the
    
Illinois Power Agency, shall establish a process or proceeding to consider the impact of a federal renewable portfolio standard, if enacted, on the operation of the alternative compliance mechanism, which shall include, but not be limited to, developing, to the extent permitted by the applicable federal statute, an appropriate methodology to apportion renewable energy credits retired as a result of alternative compliance payments made in accordance with this Section. The Commission shall commence any such process or proceeding within 35 days after enactment of a federal renewable portfolio standard.
    (e) Each alternative retail electric supplier shall, by September 1, 2010 and by September 1 of each year thereafter, prepare and submit to the Commission a report, in a format to be specified by the Commission on or before December 31, 2009, that provides information certifying compliance by the alternative retail electric supplier with this Section, including copies of all PJM-GATS and M-RETS reports, and documentation relating to banking, retiring renewable energy credits, and any other information that the Commission determines necessary to ensure compliance with this Section. An alternative retail electric supplier may file commercially or financially sensitive information or trade secrets with the Commission as provided under the rules of the Commission. To be filed confidentially, the information shall be accompanied by an affidavit that sets forth both the reasons for the confidentiality and a public synopsis of the information.
    (f) The Commission may initiate a contested case to review allegations that the alternative retail electric supplier has violated this Section, including an order issued or rule promulgated under this Section. In any such proceeding, the alternative retail electric supplier shall have the burden of proof. If the Commission finds, after notice and hearing, that an alternative retail electric supplier has violated this Section, then the Commission shall issue an order requiring the alternative retail electric supplier to:
        (1) immediately comply with this Section; and
        (2) if the violation involves a failure to procure
    
the requisite quantity of renewable energy resources or pay the applicable alternative compliance payment by the annual deadline, the Commission shall require the alternative retail electric supplier to double the applicable alternative compliance payment that would otherwise be required to bring the alternative retail electric supplier into compliance with this Section.
    If an alternative retail electric supplier fails to comply with the renewable energy resource portfolio requirement in this Section more than once in a 5-year period, then the Commission shall revoke the alternative electric supplier's certificate of service authority. The Commission shall not accept an application for a certificate of service authority from an alternative retail electric supplier that has lost certification under this subsection (f), or any corporate affiliate thereof, for at least one year after the date of revocation.
    (g) All of the provisions of this Section apply to electric utilities operating outside their service area except under item (2) of subsection (a) of this Section the quantity of renewable energy resources shall be measured as a percentage of the actual amount of electricity (megawatt-hours) supplied in the State outside of the utility's service territory during the 12-month period June 1 through May 31, commencing June 1, 2009, and the comparable 12-month period in each year thereafter except as provided in item (6) of subsection (a) of this Section.
    If any such utility fails to procure the requisite quantity of renewable energy resources by the annual deadline, then the Commission shall require the utility to double the alternative compliance payment that would otherwise be required to bring the utility into compliance with this Section.
    If any such utility fails to comply with the renewable energy resource portfolio requirement in this Section more than once in a 5-year period, then the Commission shall order the utility to cease all sales outside of the utility's service territory for a period of at least one year.
    (h) The provisions of this Section and the provisions of subsection (d) of Section 16-115 of this Act relating to procurement of renewable energy resources shall not apply to an alternative retail electric supplier that operates a combined heat and power system in this State or that has a corporate affiliate that operates such a combined heat and power system in this State that supplies electricity primarily to or for the benefit of: (i) facilities owned by the supplier, its subsidiary, or other corporate affiliate; (ii) facilities electrically integrated with the electrical system of facilities owned by the supplier, its subsidiary, or other corporate affiliate; or (iii) facilities that are adjacent to the site on which the combined heat and power system is located.
(Source: P.A. 96-33, eff. 7-10-09; 96-159, eff. 8-10-09; 96-1437, eff. 8-17-10; 97-658, eff. 1-13-12.)

    (220 ILCS 5/16-116)
    Sec. 16-116. Commission oversight of electric utilities serving retail customers outside their service areas or providing competitive, non-tariffed services.
    (a) An electric utility that has a tariff on file for delivery services may, without regard to any otherwise applicable tariffs on file, provide electric power and energy to one or more retail customers located outside its service area, but only to the extent (i) such retail customer (A) is eligible for delivery services under any delivery services tariff filed with the Commission by the electric utility in whose service area the retail customer is located and (B) has either elected to take such delivery services or has paid or contracted to pay the charges specified in Sections 16-108 and 16-114, or (ii) if such retail customer is served by a municipal system or electric cooperative, the customer is eligible for delivery services under the terms and conditions for such service established by the municipal system or electric cooperative serving that customer.
    (b) An electric utility may offer any competitive service to any customer or group of customers without filing contracts with or seeking approval of the Commission, notwithstanding any rule or regulation that would require such approval. The Commission shall not increase or decrease the prices, and may not alter or add to the terms and conditions for the utility's competitive services, from those agreed to by the electric utility and the customer or customers. Non-tariffed, competitive services shall not be subject to the provisions of the Electric Supplier Act or to Articles V, VII, VIII or IX of the Act, except to the extent that any provisions of such Articles are made applicable to alternative retail electric suppliers pursuant to Sections 16-115 and 16-115A, but shall be subject to the provisions of subsections (b) through (g) of Section 16-115A, and Section 16-115B to the same extent such provisions are applicable to the services provided by alternative retail electric suppliers.
    (c) Electric utilities serving retail customers outside their service areas shall be subject to the requirements of paragraph (5) of subsection (d) of Section 16-115 of the Public Utilities Act, except that the numerators referred to in that subsection (d) shall be the utility's retail market sales of electricity (expressed in kilowatthours sold) in the State outside of the utility's service territory in the prior month.
(Source: P.A. 95-1027, eff. 6-1-09.)

    (220 ILCS 5/16-117)
    Sec. 16-117. Commission consumer education program.
    (a) The restructuring of the electricity industry will create a new electricity market with new marketers and sellers offering new goods and services, many of which the average consumer will not be able to readily evaluate. It is the intent of the General Assembly that (i) electricity consumers be provided with sufficient and reliable information so that they are able to compare and make informed selections of products and services provided in the electricity market; and (ii) mechanisms be provided to enable consumers to protect themselves from marketing practices that are unfair or abusive.
    (b) The Commission shall maintain consumer education information to help residential and small commercial retail customers understand their service options in a competitive electric services market, and their rights and responsibilities.
    (c) Not more than 90 days after the effective date of this amendatory Act of the 97th General Assembly, the Commission shall direct the Office of Retail Market Development to review the existing consumer education information for residential and small commercial customers and consider whether updates are necessary. The Office of Retail Market Development shall seek input from interested persons, including alternative retail electric suppliers, electric utilities, the Attorney General, and the Citizens Utility Board, to further its review of the consumer education materials and possible proposed changes. Within 4 months after the start of the review, the Office of Retail Market Development shall submit recommendations to the Commission for approval.
    (d) (Blank).
    (e) At a minimum, the consumer education information submitted to the Commission by the Office of Retail Market Development shall include concise explanations or descriptions of the following:
        (1) the structure of the electric utility industry

    
following this amendatory Act of 1997 and a glossary of basic terms;
        (2) the choices available to consumers to take
    
electric service from an alternative retail electric supplier or remain as a retail customer of an electric utility;
        (3) a customer's rights, risks and responsibilities
    
in receiving service from an alternative retail electric supplier or remaining as a retail customer of an electric utility;
        (4) the legal obligations of alternative retail
    
electric suppliers;
        (5) those services that may be offered on a
    
competitive basis in a deregulated electric services market, including services that could be packaged with the delivery of electric power and energy;
        (6) services that an electric utility is required to
    
provide pursuant to tariffed rates;
        (7) the components of a bill that could be received
    
by a customer taking delivery services;
        (8) the complaint procedures set forth in Section
    
10-108 of this Act by which consumers may seek a redress of grievances against an electric utility or an alternative retail electric supplier and a list of phone numbers of the Commission, the Attorney General or other entities that can provide information and assistance to customers; and
        (9) additional information available from the
    
Commission upon request.
    (f) Within 45 days following the submission required of the Office of Retail Market Development by subsection (c) of this Section, the Commission shall approve or disapprove the consumer education information.
    (g) Once approved by the Commission, the consumer education information shall be provided as follows:
        (1) If the electric utility bills residential or
    
small commercial retail customers directly, then the bill shall include the Commission's electric education internet address in the space reserved for alternative retail electric supplier messages.
        (2) Alternative retail electric suppliers shall
    
provide the Commission's electric education internet address to all residential and small commercial retail customers.
        (3) (Blank).
        (4) The Commission shall make the following
    
information available on its web site and printed information from the web site available to the public upon request and at no charge:
            (A) all consumer education information developed
        
by the Office of Retail Market Development and approved by the Commission;
            (B) a list of all certified alternative retail
        
electric suppliers serving residential and small commercial retail customers within the service territory of each electric utility;
            (C) a list of alternative retail electric
        
suppliers serving residential or small commercial retail customers which have been found in the last 3 years by the Commission pursuant to Section 10-108 to have failed to provide service in accordance with the terms of their contracts with such retail customers; and
            (D) guidelines to assist customers in determining
        
which energy supplier is most appropriate for each customer.
    (h) The Commission may also adopt a uniform disclosure form which alternative retail electric suppliers would be required to complete enabling consumers to compare prices, terms and conditions offered by such suppliers.
    (i) The Commission shall make available to the public staff with the ability and knowledge to respond to consumer inquiries.
    (j) (Blank).
    (k) (Blank).
(Source: P.A. 97-222, eff. 7-28-11.)

    (220 ILCS 5/16-118)
    Sec. 16-118. Services provided by electric utilities to alternative retail electric suppliers.
    (a) It is in the best interest of Illinois energy consumers to promote fair and open competition in the provision of electric power and energy and to prevent anticompetitive practices in the provision of electric power and energy. Therefore, to the extent an electric utility provides electric power and energy or delivery services to alternative retail electric suppliers and such services are not subject to the jurisdiction of the Federal Energy Regulatory Commission, and are not competitive services, they shall be provided through tariffs that are filed with the Commission, pursuant to Article IX of this Act. Each electric utility shall permit alternative retail electric suppliers to interconnect facilities to those owned by the utility provided they meet established standards for such interconnection, and may provide standby or other services to alternative retail electric suppliers. The alternative retail electric supplier shall sign a contract setting forth the prices, terms and conditions for interconnection with the electric utility and the prices, terms and conditions for services provided by the electric utility to the alternative retail electric supplier in connection with the delivery by the electric utility of electric power and energy supplied by the alternative retail electric supplier.
    (b) An electric utility shall file a tariff pursuant to Article IX of the Act that would allow alternative retail electric suppliers or electric utilities other than the electric utility in whose service area retail customers are located to issue single bills to the retail customers for both the services provided by such alternative retail electric supplier or other electric utility and the delivery services provided by the electric utility to such customers. The tariff filed pursuant to this subsection shall (i) require partial payments made by retail customers to be credited first to the electric utility's tariffed services, (ii) impose commercially reasonable terms with respect to credit and collection, including requests for deposits, (iii) retain the electric utility's right to disconnect the retail customers, if it does not receive payment for its tariffed services, in the same manner that it would be permitted to if it had billed for the services itself, and (iv) require the alternative retail electric supplier or other electric utility that elects the billing option provided by this tariff to include on each bill to retail customers an identification of the electric utility providing the delivery services and a listing of the charges applicable to such services. The tariff filed pursuant to this subsection may also include other just and reasonable terms and conditions. In addition, an electric utility, an alternative retail electric supplier or electric utility other than the electric utility in whose service area the customer is located, and a customer served by such alternative retail electric supplier or other electric utility, may enter into an agreement pursuant to which the alternative retail electric supplier or other electric utility pays the charges specified in Section 16-108, or other customer-related charges, including taxes and fees, in lieu of such charges being recovered by the electric utility directly from the customer.
    (c) An electric utility with more than 100,000 customers shall file a tariff pursuant to Article IX of this Act that provides alternative retail electric suppliers, and electric utilities other than the electric utility in whose service area the retail customers are located, with the option to have the electric utility purchase their receivables for power and energy service provided to residential retail customers and non-residential retail customers with a non-coincident peak demand of less than 400 kilowatts. Receivables for power and energy service of alternative retail electric suppliers or electric utilities other than the electric utility in whose service area the retail customers are located shall be purchased by the electric utility at a just and reasonable discount rate to be reviewed and approved by the Commission after notice and hearing. The discount rate shall be based on the electric utility's historical bad debt and any reasonable start-up costs and administrative costs associated with the electric utility's purchase of receivables. The discounted rate for purchase of receivables shall be included in the tariff filed pursuant to this subsection (c). The discount rate filed pursuant to this subsection (c) shall be subject to periodic Commission review. The electric utility retains the right to impose the same terms on retail customers with respect to credit and collection, including requests for deposits, and retain the electric utility's right to disconnect the retail customers, if it does not receive payment for its tariffed services or purchased receivables, in the same manner that it would be permitted to if the retail customers purchased power and energy from the electric utility. The tariff filed pursuant to this subsection (c) shall permit the electric utility to recover from retail customers any uncollected receivables that may arise as a result of the purchase of receivables under this subsection (c), may also include other just and reasonable terms and conditions, and shall provide for the prudently incurred costs associated with the provision of this service pursuant to this subsection (c). Nothing in this subsection (c) permits the double recovery of bad debt expenses from customers.
    (d) An electric utility with more than 100,000 customers shall file a tariff pursuant to Article IX of this Act that would provide alternative retail electric suppliers or electric utilities other than the electric utility in whose service area retail customers are located with the option to have the electric utility produce and provide single bills to the retail customers for both the electric power and energy service provided by the alternative retail electric supplier or other electric utility and the delivery services provided by the electric utility to the customers. The tariffs filed pursuant to this subsection shall require the electric utility to collect and remit customer payments for electric power and energy service provided by alternative retail electric suppliers or electric utilities other than the electric utility in whose service area retail customers are located. The tariff filed pursuant to this subsection shall require the electric utility to include on each bill to retail customers an identification of the alternative retail electric supplier or other electric utility that elects the billing option. The tariff filed pursuant to this subsection (d) may also include other just and reasonable terms and conditions and shall provide for the recovery of prudently incurred costs associated with the provision of service pursuant to this subsection (d). The costs associated with the provision of service pursuant to this Section shall be subject to periodic Commission review.
    (e) An electric utility with more than 100,000 customers in this State shall file a tariff pursuant to Article IX of this Act that provides alternative retail electric suppliers, and electric utilities other than the electric utility in whose service area the retail customers are located, with the option to have the electric utility purchase 2 billing cycles worth of uncollectible receivables for power and energy service provided to residential retail customers and to non-residential retail customers with a non-coincident peak demand of less than 400 kilowatts upon returning that customer to that electric utility for delivery and energy service after that alternative retail electric supplier, or an electric utility other than the electric utility in whose service area the retail customer is located, has made reasonable collection efforts on that account. Uncollectible receivables for power and energy service of alternative retail electric suppliers, or electric utilities other than the electric utility in whose service area the retail customers are located, shall be purchased by the electric utility at a just and reasonable discount rate to be reviewed and approved by the Commission, after notice and hearing. The discount rate shall be based on the electric utility's historical bad debt for receivables that are outstanding for a similar length of time and any reasonable start-up costs and administrative costs associated with the electric utility's purchase of receivables. The discounted rate for purchase of uncollectible receivables shall be included in the tariff filed pursuant to this subsection (e). The electric utility retains the right to impose the same terms on these retail customers with respect to credit and collection, including requests for deposits, and retains the right to disconnect these retail customers, if it does not receive payment for its tariffed services or purchased receivables, in the same manner that it would be permitted to if the retail customers had purchased power and energy from the electric utility. The tariff filed pursuant to this subsection (e) shall permit the electric utility to recover from retail customers any uncollectable receivables that may arise as a result of the purchase of uncollectible receivables under this subsection (e), may also include other just and reasonable terms and conditions, and shall provide for the prudently incurred costs associated with the provision of this service pursuant to this subsection (e). Nothing in this subsection (e) permits the double recovery of utility bad debt expenses from customers. The electric utility may file a joint tariff for this subsection (e) and subsection (c) of this Section.
(Source: P.A. 95-700, eff. 11-9-07.)

    (220 ILCS 5/16-119)
    Sec. 16-119. Switching suppliers. An electric utility or an alternative retail electric supplier may establish a term of service, notice period for terminating service and provisions governing early termination through a tariff or contract. A customer may change its supplier subject to tariff or contract terms and conditions. Any notice provisions; or provision for a fee, charge or penalty with early termination of a contract; shall be conspicuously disclosed in any tariff or contract. A customer shall remain responsible for any unpaid charges owed to an electric utility or alternative retail electric supplier at the time it switches to another provider.
(Source: P.A. 90-561, eff. 12-16-97.)

    (220 ILCS 5/16-119A)
    Sec. 16-119A. Functional separation.
    (a) Within 90 days after the effective date of this amendatory Act of 1997, the Commission shall open a rulemaking proceeding to establish standards of conduct for every electric utility described in subsection (b). To create efficient competition between suppliers of generating services and sellers of such services at retail and wholesale, the rules shall allow all customers of a public utility that distributes electric power and energy to purchase electric power and energy from the supplier of their choice in accordance with the provisions of Section 16-104. In addition, the rules shall address relations between providers of any 2 services described in subsection (b) to prevent undue discrimination and promote efficient competition. Provided, however, that a proposed rule shall not be published prior to May 15, 1999.
    (b) The Commission shall also have the authority to investigate the need for, and adopt rules requiring, functional separation between the generation services and the delivery services of those electric utilities whose principal service area is in Illinois as necessary to meet the objective of creating efficient competition between suppliers of generating services and sellers of such services at retail and wholesale. After January 1, 2003, the Commission shall also have the authority to investigate the need for, and adopt rules requiring, functional separation between an electric utility's competitive and non-competitive services.
    (b-5) If there is a change in ownership of a majority of the voting capital stock of an electric utility or the ownership or control of any entity that owns or controls a majority of the voting capital stock of an electric utility, the electric utility shall have the right to file with the Commission a new plan. The newly filed plan shall supersede any plan previously approved by the Commission pursuant to this Section for that electric utility, subject to Commission approval. This subsection only applies to the extent that the Commission rules for the functional separation of delivery services and generation services provide an electric utility with the ability to select from 2 or more options to comply with this Section. The electric utility may file its revised plan with the Commission up to one calendar year after the conclusion of the sale, purchase, or any other transfer of ownership described in this subsection. In all other respects, an electric utility must comply with the Commission rules in effect under this Section. The Commission may promulgate rules to implement this subsection. This subsection shall have no legal effect after January 1, 2005.
    (c) In establishing or considering the need for rules under subsections (a) and (b), the Commission shall take into account the effects on the cost and reliability of service and the obligation of the utility to provide bundled service under this Act. The Commission shall adopt rules that are a cost effective means to ensure compliance with this Section.
    (d) Nothing in this Section shall be construed as imposing any requirements or obligations that are in conflict with federal law.
(Source: P.A. 92-756, eff. 8-2-02.)

    (220 ILCS 5/16-120)
    Sec. 16-120. Development of competitive market; Commission study and reports; investigation.
    (a) On or before December 31, 1999 and once every 3 years thereafter, the Commission shall monitor and analyze patterns of entry and exit, applications for entry and exit, and any barriers to entry or participation that may exist, for services provided under this Article; shall analyze any impediments to the establishment of a fully competitive energy and power market in Illinois; and shall include its findings together with appropriate recommendations for legislative action in a report to the General Assembly.
    (b) Beginning in 2001, and ending in 2006, the Commission shall prepare an annual report regarding the development of electricity markets in Illinois which shall be filed by April 1 of each year with the Joint Committee on Legislative Support Services of the General Assembly and the Governor and which shall be publicly available. Such report shall include, at a minimum, the following information:
        (1) the aggregate annual peak demand of retail

    
customers in the State of Illinois in the preceding calendar year;
        (2) the total annual kilowatt-hours delivered and
    
sold to retail customers in the State of Illinois by each electric utility within its own service territory, each electric utility outside its service territory, and alternative retail electric suppliers in the preceding calendar year;
        (3) the percentage of the total kilowatt-hours
    
delivered and sold to retail customers in the State of Illinois in the preceding calendar year by each electric utility within its service territory, each electric utility outside its service territory, and each alternative retail electric supplier; and
        (4) any other information the Commission considers
    
significant in assessing the development of Illinois electricity markets, which may include, to the extent available, information similar to that described in items 1, 2 and 3 with respect to cogeneration, self-generation and other sources of electric power and energy provided to customers that do not take delivery services or bundled electric utility services.
    The Commission may also include such other information as it deems to be necessary or beneficial in describing or explaining the results of its Report. The Report required by this Section shall be adopted by a vote of the full Commission prior to filing. Proprietary or confidential information shall not be disclosed publicly. Nothing contained in this Section shall prohibit the Commission from taking actions that would otherwise be allowed under this Act.
    (c) The Commission shall prepare a report on the value of municipal aggregation of electricity customers. The report shall be filed with the General Assembly and the Governor no later than January 15, 2003 and shall be publicly available. The report shall, at a minimum, include:
        (1) a description and analysis of actual and
    
potential forms of aggregation of electricity customers in Illinois and in the other states, including aggregation through municipal, affinity, and other organizations and through aggregation of consumer purchases of electricity from renewable energy sources;
        (2) estimates of the potential benefits of municipal
    
aggregation to Illinois electricity customers in at least 5 specific municipal examples comparing their costs under bundled rates and unbundled rates, including real-time prices;
        (3) a description of the barriers to municipal and
    
other forms of aggregation in Illinois, including legal, economic, informational, and other barriers; and
        (4) options for legislative action to foster
    
municipal and other forms of aggregation of electricity customers.
    In preparing the report, the Commission shall consult with persons involved in aggregation or the study of aggregation of electricity customers in Illinois, including municipalities, utilities, aggregators, and non-profit organizations. The provisions of Section 16-122 notwithstanding, the Commission may request and utilities shall provide such aggregated load data as may be necessary to perform the analyses required by this subsection; provided, however, proprietary or confidential information shall not be disclosed publicly.
(Source: P.A. 92-585, eff. 6-26-02.)

    (220 ILCS 5/16-121)
    Sec. 16-121. Non-discrimination; adoption of rules and regulations. The Commission shall adopt rules and regulations no later than 180 days after the effective date of this amendatory Act of 1997 governing the relationship between the electric utility and its affiliates, and ensuring nondiscrimination in services provided to the utility's affiliate and any alternative retail electric supplier, including without limitation, cost allocation, cross-subsidization and information sharing.
(Source: P.A. 90-561, eff. 12-16-97.)

    (220 ILCS 5/16-122)
    Sec. 16-122. Customer information.
    (a) Upon the request of a retail customer, or a person who presents verifiable authorization and is acting as the customer's agent, and payment of a reasonable fee, electric utilities shall provide to the customer or its authorized agent the customer's billing and usage data.
    (b) Upon request from any alternative retail electric supplier and payment of a reasonable fee, an electric utility serving retail customers in its service area shall make available generic information concerning the usage, load shape curve or other general characteristics of customers by rate classification. Provided however, no customer specific billing, usage or load shape data shall be provided under this subsection unless authorization to provide such information is provided by the customer pursuant to subsection (a) of this Section.
    (c) Upon request from a unit of local government and payment of a reasonable fee, an electric utility shall make available information concerning the usage, load shape curves, and other characteristics of customers by customer classification and location within the boundaries of the unit of local government, however, no customer specific billing, usage, or load shape data shall be provided under this subsection unless authorization to provide that information is provided by the customer.
    (d) All such customer information shall be made available in a timely fashion in an electronic format, if available.
(Source: P.A. 92-585, eff. 6-26-02.)

    (220 ILCS 5/16-123)
    Sec. 16-123. Establishment of customer information centers for electric utilities and alternative retail electric suppliers. All electric utilities and alternative retail electric suppliers shall be required to maintain a customer call center where customers can reach a representative and receive current information. Customers shall periodically be notified on how to reach the call center. The Commission shall have the authority to establish reporting requirements for such centers.
(Source: P.A. 90-561, eff. 12-16-97.)

    (220 ILCS 5/16-124)
    Sec. 16-124. Metering for residential and small commercial retail customers. An electric utility shall not require a residential or small commercial retail customer to take additional metering or metering capability as a condition of taking delivery services unless the Commission finds, after notice and hearing, that additional metering or metering capability is required to meet reliability requirements. Alternative retail electric suppliers serving such customers may provide such additional metering or metering capability at their own expense or take such additional metering or metering capability from the utility as a tariffed service. Any additional metering requirements shall be imposed in a nondiscriminatory manner. Nothing in this subsection shall be construed to prevent the normal maintenance, replacement or upgrade of meters as required to comply with Commission rules.
(Source: P.A. 90-561, eff. 12-16-97.)

    (220 ILCS 5/16-125)
    Sec. 16-125. Transmission and distribution reliability requirements.
    (a) To assure the reliable delivery of electricity to all customers in this State and the effective implementation of the provisions of this Article, the Commission shall, within 180 days of the effective date of this Article, adopt rules and regulations for assessing and assuring the reliability of the transmission and distribution systems and facilities that are under the Commission's jurisdiction.
    (b) These rules and regulations shall require each electric utility or alternative retail electric supplier owning, controlling, or operating transmission and distribution facilities and equipment subject to the Commission's jurisdiction, referred to in this Section as "jurisdictional entities", to adopt and implement procedures for restoring transmission and distribution services to customers after transmission or distribution outages on a nondiscriminatory basis without regard to whether a customer has chosen the electric utility, an affiliate of the electric utility, or another entity as its provider of electric power and energy. These rules and regulations shall also, at a minimum, specifically require each jurisdictional entity to submit annually to the Commission.
        (1) the number and duration of planned and unplanned

    
outages during the prior year and their impacts on customers;
        (2) outages that were controllable and outages that
    
were exacerbated in scope or duration by the condition of facilities, equipment or premises or by the actions or inactions of operating personnel or agents;
        (3) customer service interruptions that were due
    
solely to the actions or inactions of an alternative retail electric supplier or a public utility in supplying power or energy;
        (4) a detailed report of the age, current condition,
    
reliability and performance of the jurisdictional entity's existing transmission and distribution facilities, which shall include, without limitation, the following data:
            (i) a summary of the jurisdictional entity's
        
outages and voltage variances reportable under the Commission's rules;
            (ii) the jurisdictional entity's expenditures for
        
transmission construction and maintenance, the ratio of those expenditures to the jurisdictional entity's transmission investment, and the average remaining depreciation lives of the entity's transmission facilities, expressed as a percentage of total depreciation lives;
            (iii) the jurisdictional entity's expenditures
        
for distribution construction and maintenance, the ratio of those expenditures to the jurisdictional entity's distribution investment, and the average remaining depreciation lives of the entity's distribution facilities, expressed as a percentage of total depreciation lives;
            (iv) a customer satisfaction survey covering,
        
among other areas identified in Commission rules, reliability, customer service, and understandability of the jurisdictional entity's services and prices; and
            (v) the corresponding information, in the same
        
format, for the previous 3 years, if available;
        (5) a plan for future investment and reliability
    
improvements for the jurisdictional entity's transmission and distribution facilities that will ensure continued reliable delivery of energy to customers and provide the delivery reliability needed for fair and open competition; and
        (6) a report of the jurisdictional entity's
    
implementation of its plan filed pursuant to subparagraph (5) for the previous reporting period.
    (c) The Commission rules shall set forth the criteria that will be used to assess each jurisdictional entity's annual report and evaluate its reliability performance. Such criteria must take into account, at a minimum: the items required to be reported in subsection (b); the relevant characteristics of the area served; the age and condition of the system's equipment and facilities; good engineering practices; the costs of potential actions; and the benefits of avoiding the risks of service disruption.
    (d) At least every 3 years, beginning in the year the Commission issues the rules required by subsection (a) or the following year if the rules are issued after June 1, the Commission shall assess the annual report of each jurisdictional entity and evaluate its reliability performance. The Commission's evaluation shall include specific identification of, and recommendations concerning, any potential reliability problems that it has identified as a result of its evaluation.
    (e) In the event that more than either (i) 30,000 (or some other number, but only as provided by statute) of the total customers or (ii) 0.8% (or some other percentage, but only as provided by statute) of the total customers, whichever is less, of an electric utility are subjected to a continuous power interruption of 4 hours or more that results in the transmission of power at less than 50% of the standard voltage, or that results in the total loss of power transmission, the utility shall be responsible for compensating customers affected by that interruption for 4 hours or more for all actual damages, which shall not include consequential damages, suffered as a result of the power interruption. The utility shall also reimburse the affected municipality, county, or other unit of local government in which the power interruption has taken place for all emergency and contingency expenses incurred by the unit of local government as a result of the interruption. A waiver of the requirements of this subsection may be granted by the Commission in instances in which the utility can show that the power interruption was a result of any one or more of the following causes:
        (1) Unpreventable damage due to weather events or
    
conditions.
        (2) Customer tampering.
        (3) Unpreventable damage due to civil or
    
international unrest or animals.
        (4) Damage to utility equipment or other actions by a
    
party other than the utility, its employees, agents, or contractors.
Loss of revenue and expenses incurred in complying with this subsection may not be recovered from ratepayers.
    (f) In the event of a power surge or other fluctuation that causes damage and affects more than either (i) 30,000 (or some other number, but only as provided by statute) of the total customers or (ii) 0.8% (or some other percentage, but only as provided by statute) of the total customers, whichever is less, the electric utility shall pay to affected customers the replacement value of all goods damaged as a result of the power surge or other fluctuation unless the utility can show that the power surge or other fluctuation was due to one or more of the following causes:
        (1) Unpreventable damage due to weather events or
    
conditions.
        (2) Customer tampering.
        (3) Unpreventable damage due to civil or
    
international unrest or animals.
        (4) Damage to utility equipment or other actions by a
    
party other than the utility, its employees, agents, or contractors.
Loss of revenue and expenses incurred in complying with this subsection may not be recovered from ratepayers. Customers with respect to whom a waiver has been granted by the Commission pursuant to subparagraphs (1)-(4) of subsections (e) and (f) shall not count toward the either (i) 30,000 (or some other number, but only as provided by statute) of the total customers or (ii) 0.8% (or some other percentage, but only as provided by statute) of the total customers required therein.
    (g) Whenever an electric utility must perform planned or routine maintenance or repairs on its equipment that will result in transmission of power at less than 50% of the standard voltage, loss of power, or power fluctuation (as defined in subsection (f)), the utility shall make reasonable efforts to notify potentially affected customers no less than 24 hours in advance of performance of the repairs or maintenance.
    (h) Remedies provided for under this Section may be sought exclusively through the Illinois Commerce Commission as provided under Section 10-109 of this Act. Damages awarded under this Section for a power interruption shall be limited to actual damages, which shall not include consequential damages, and litigation costs. A utility's request for a waiver of this Section shall be timely if filed no later than 30 days after the date on which a claim is filed with the Commission seeking damages or expense reimbursement under this Section. No utility shall be liable under this Section while a request for waiver is pending. Damage awards may not be paid out of utility rate funds.
    (i) The provisions of this Section shall not in any way diminish or replace other civil or administrative remedies available to a customer or a class of customers.
    (j) The Commission shall by rule require an electric utility to maintain service records detailing information on each instance of transmission of power at less than 50% of the standard voltage, loss of power, or power fluctuation (as defined in subsection (f)), that affects 10 or more customers. Occurrences that are momentary shall not be required to be recorded or reported. The service record shall include, for each occurrence, the following information:
        (1) The date.
        (2) The time of occurrence.
        (3) The duration of the incident.
        (4) The number of customers affected.
        (5) A description of the cause.
        (6) The geographic area affected.
        (7) The specific equipment involved in the
    
fluctuation or interruption.
        (8) A description of measures taken to restore
    
service.
        (9) A description of measures taken to remedy the
    
cause of the power interruption or fluctuation.
        (10) A description of measures taken to prevent
    
future occurrence.
        (11) The amount of remuneration, if any, paid to
    
affected customers.
        (12) A statement of whether the fixed charge was
    
waived for affected customers.
    Copies of the records containing this information shall be available for public inspection at the utility's offices, and copies thereof may be obtained upon payment of a fee not exceeding the reasonable cost of reproduction. A copy of each record shall be filed with the Commission and shall be available for public inspection. Copies of the records may be obtained upon payment of a fee not exceeding the reasonable cost of reproduction.
    (k) The requirements of subsections (e) through (j) of this Section shall apply only to an electric public utility having 100,000 or more customers.
(Source: P.A. 95-1027, eff. 6-1-09.)

    (220 ILCS 5/16-125A)
    Sec. 16-125A. Consolidated billing provision for established intergovernmental agreement participants.
    (a) The tariffs of each electric utility serving at least 1,000,000 customers shall permit governmental customers acting through an intergovernmental agreement that was in effect 30 days prior to the date specified in subsection (b) and which provides for these governmental customers to work cooperatively in the purchase of electric energy to aggregate their monthly kilowatt-hour energy usage and monthly kilowatt billing demand.
    (b) In implementing the provisions of this Section, the rates and charges applicable under the combined billing tariff of the serving utility in effect on May 1, 1997 shall apply to all load of eligible government customers selected by the governmental customers including, but not limited to, load served under contract.
    (c) For purposes of this Section, "governmental customers" shall mean any customer that is a municipality, municipal corporation, unit of local government, park district, school district, community college district, forest preserve district, special district, public corporation, body politic and corporate, sanitary or water reclamation district, or other local government agencies, including any entity created by intergovernmental agreement among any of the foregoing entities to implement the arrangements permitted by subsections (a) and (b) of this Section.
    (d) Electric utilities shall file tariffs that comply with the requirements of this Section within 60 days after the effective date of this amendatory Act of 1997.
(Source: P.A. 90-561, eff. 12-16-97.)

    (220 ILCS 5/16-126)
    Sec. 16-126. Membership in an independent system operator.
    (a) The General Assembly finds that the establishment of one or more independent system operators or their functional equivalents is required to facilitate the development of an open and efficient marketplace for electric power and energy to the benefit of Illinois consumers. Therefore, each Illinois electric utility owning or controlling transmission facilities or providing transmission services in Illinois and that is a member of the Mid-American Interconnected Network as of the effective date of this amendatory Act of 1997 shall submit for approval to the Federal Energy Regulatory Commission an application for establishing or joining an independent system operator that shall:
        (1) independently manage and control transmission

    
facilities of any electric utility;
        (2) provide for nondiscriminatory access to and use
    
of the transmission system for buyers and sellers of electricity;
        (3) direct the transmission activities of the control
    
area operators;
        (4) coordinate, plan, and order the installation of
    
new transmission facilities;
        (5) adopt inspection, maintenance, repair, and
    
replacement standards for the transmission facilities under its control and direct maintenance, repair, and replacement of all facilities under its control; and
        (6) implement procedures and act to assure the
    
provision of adequate and reliable service.
    These standards shall be consistent with reliability criteria no less stringent than those established by the Mid-American Interconnected Network and the North American Electric Reliability Council or their successors.
    (b) The requirements of this Section may be met by joining or establishing a regional independent system operator that meets the criteria enumerated in subsections (a), (c), and (d) of this Section, as determined by the Commission. To achieve the objectives set forth in subsection (a), the State of Illinois, through the appropriate officers, departments, and agencies, shall work cooperatively with the appropriate officials and agencies of those States contiguous to this State and the Federal Energy Regulatory Commission towards the formation of one or more regional independent system operators.
    (c) The independent system operator's governance structure must be fair and nondiscriminatory, and the independent system operator must be independent of any one market participant or class of participants. The independent system operator's rules of governance must prevent control, or the appearance of control, of decision-making by any class of participants.
    (d) Participants in the independent system operator shall make available to the independent system operator all information required by the independent system operator in performance of its functions described herein. The independent system operator and the electric utilities participating in the independent system operator shall make all filings required by the Federal Energy Regulatory Commission. The independent system operator shall ensure that additional filings at the Federal Energy Regulatory Commission request confirmation of the relevant provisions of this amendatory Act of 1997.
    (e) If a spot market, exchange market, or other market-based mechanism providing transparent real-time market prices for electric power has not been developed, the independent system operator or a closely cooperating agent of the independent system operator may provide an efficient competitive power exchange auction for electric power and energy, open on a nondiscriminatory basis to all suppliers, which meets the loads of all auction customers at efficient prices.
    (f) For those electric utilities referred to in subsection (a) which have not filed with the Federal Energy Regulatory Commission by June 30, 1998 an application for establishment or participation in an independent system operator or if such application has not been approved by the Federal Energy Regulatory Commission by March 31, 1999, a 5 member Oversight Board shall be formed. The Oversight Board shall (1) oversee the creation of an Illinois independent system operator and (2) determine the composition and initial terms of service of, and appoint the initial members of, the Illinois independent system operator board of directors. The Oversight Board shall consist of the following: (1) 3 persons appointed by the Governor; (2) one person appointed by the Speaker of the House of Representatives; and (3) one person appointed by the President of the Senate. The Oversight Board shall take the steps that are necessary to ensure the earliest possible incorporation of an Illinois independent system operator under the Business Corporation Act of 1983, and shall serve until the Illinois independent system operator is incorporated.
    (g) After notice and hearing, the Commission shall require each electric utility referred to in subsection (a), that is not participating in an independent system operator meeting the requirements of subsections (a) and (c), to seek authority from the Federal Energy Regulatory Commission to transfer functional control of transmission facilities to the Illinois independent system operator for control by the Illinois independent system operator consistent with the requirements of subsection (a). Upon approval by the Federal Energy Regulatory Commission, electric utilities may also elect to transfer ownership of transmission facilities to the Illinois independent system operator. Nothing in this Act shall be deemed to preclude the Illinois independent system operator from (1) seeking authority, as necessary, to merge with or otherwise combine its operations with those of one or more other entities authorized to provide transmission services, (2) purchasing or leasing transmission assets from transmission-owning entities not required by this Section to lease transmission facilities to the Illinois independent system operator, or (3) operating as a transmission public utility under the Federal Power Act.
    (h) Any other owner of transmission facilities in Illinois not required by this Section to participate in an independent system operator shall be permitted, but not required, to become a member of the Illinois independent system operator.
    (i) The Illinois independent system operator created under this Section, and any other independent system operator authorized by the Federal Energy Regulatory Commission to provide transmission services as a public utility under the Federal Power Act within the State of Illinois, shall be deemed to be a public utility for purposes of Section 8-503 and 8-509 of this Act. An independent system operator or regional transmission organization that is the subject of an order entered by the Commission under Section 8-503 need not possess a certificate of service authority under Section 8-406 in order to be authorized to take the actions set forth in Section 8-509.
    (j) Electric utilities referred to in subsection (a) may withdraw from the Illinois independent system operator upon becoming a member of an independent system operator or operators conforming with the criteria in subsections (a) and (c) and whose formation and operation has been approved by the Federal Energy Regulatory Commission. This subsection does not relieve any electric utility of any obligations under Federal law.
    (k) Nothing in this Section shall be construed as imposing any requirements or obligations that are in conflict with federal law.
    (l) A regional transmission organization created under the rules of the Federal Energy Regulatory Commission shall be considered to be the functional equivalent of an independent system operator for purposes of this Section, and an electric utility shall be deemed to meet its obligations under this Section through membership in a regional transmission organization that fulfills the requirements of an independent system operator under this Section.
(Source: P.A. 92-12, eff. 7-1-01.)

    (220 ILCS 5/16-126.1)
    Sec. 16-126.1. Regional transmission organization memberships. The State shall not directly or indirectly prohibit an electric utility that on December 31, 2005 provided electric service to at least 100,000 customers in Illinois from membership in a Federal Energy Regulatory Commission approved regional transmission organization of its choosing. Nothing in this Section limits any authority the Commission otherwise has to regulate that electric utility. This Section ceases to be effective on July 1, 2022 unless extended by the General Assembly by law.
(Source: P.A. 95-481, eff. 8-28-07.)

    (220 ILCS 5/16-127)
    Sec. 16-127. Environmental disclosure.
    (a) Effective January 1, 2013, every electric utility and alternative retail electric supplier shall provide the following information, to the maximum extent practicable, to its customers on a quarterly basis:
        (i) the known sources of electricity supplied,

    
broken-out by percentages, of biomass power, coal-fired power, hydro power, natural gas-fired power, nuclear power, oil-fired power, solar power, wind power and other resources, respectively;
        (ii) a pie-chart that graphically depicts the
    
percentages of the sources of the electricity supplied as set forth in subparagraph (i) of this subsection; and
        (iii) a pie-chart that graphically depicts the
    
quantity of renewable energy resources procured pursuant to Section 1-75 of the Illinois Power Agency Act as a percentage of electricity supplied to serve eligible retail customers as defined in Section 16-111.5(a) of this Act.
    (b) In addition, every electric utility and alternative retail electric supplier shall provide, to the maximum extent practicable, to its customers on a quarterly basis, a standardized chart in a format to be determined by the Commission in a rule following notice and hearings which provides the amounts of carbon dioxide, nitrogen oxides and sulfur dioxide emissions and nuclear waste attributable to the known sources of electricity supplied as set forth in subparagraph (i) of subsection (a) of this Section.
    (c) The electric utilities and alternative retail electric suppliers may provide their customers with such other information as they believe relevant to the information required in subsections (a) and (b) of this Section. All of the information required in subsections (a) and (b) of this Section shall be made available by the electric utilities or alternative retail electric suppliers either in an electronic medium, such as on a website or by electronic mail, or through the U.S. Postal Service.
    (d) For the purposes of subsection (a) of this Section, "biomass" means dedicated crops grown for energy production and organic wastes.
    (e) All of the information provided in subsections (a) and (b) of this Section shall be presented to the Commission for inclusion in its World Wide Web Site.
(Source: P.A. 97-1092, eff. 1-1-13.)

    (220 ILCS 5/16-128)
    Sec. 16-128. Provisions related to utility employees.
    (a) The General Assembly finds:
        (1) The reliability and safety of the electric system

    
has depended and depends on a workforce of skilled and dedicated employees, equipped with technical training and experience.
        (2) The integrity and reliability of the system also
    
requires the industry's commitment to invest in regular inspection and maintenance, to assure that it can withstand the demands of heavy service requirements and emergency situations.
        (3) It is in the State's interest to protect the
    
interests of utility employees who have and continue to dedicate themselves to assuring reliable service to the citizens of this State, and who might otherwise be economically displaced in a restructured industry.
    The General Assembly further finds that it is necessary to assure that employees of electric utilities and employees of contractors or subcontractors performing work on behalf of an electric utility operating in the deregulated industry have the requisite skills, knowledge, training, experience, and competence to provide reliable and safe electrical service under this Act.
    The General Assembly also finds that it is necessary to assure that employees of alternative retail electric suppliers and employees of contractors or subcontractors performing work on behalf of an alternative retail electric supplier operating in the deregulated industry have the requisite skills, knowledge, training, experience, and competence to provide reliable and safe electrical service under this Act.
    To ensure that these findings and prerequisites for reliable and safe electrical service continue to prevail, each alternative retail electric supplier, electric utility, and contractors and subcontractors performing work on behalf of an electric utility or alternative retail electric supplier must demonstrate the competence of their respective employees to work on the distribution system.
    The knowledge, skill, training, experience, and competence levels to be demonstrated shall be consistent with those required of or by the electric utilities in this State as of January 1, 2007, with respect to their employees and employees of contractors or subcontractors performing work on their behalf. Nothing in this Section shall prohibit an electric utility from establishing knowledge, skill, training, experience, and competence levels greater than those required as of January 1, 2007.
    An adequate demonstration of requisite knowledge, skill, training, experience, and competence shall include, at a minimum, completion or current participation and ultimate completion by the employee of an accredited or otherwise recognized apprenticeship program for the particular craft, trade or skill, or specified and several years of employment performing a particular work function that is utilized by an electric utility.
    Notwithstanding any law, tariff, Commission rule, order, or decision to the contrary, the Commission shall have an affirmative statutory obligation to ensure that an electric utility is employing employees, contractors, and subcontractors with employees who meet the requirements of subsection (a) of this Section when installing, constructing, operating, and maintaining generation, transmission, or distribution facilities and equipment within this State pursuant to any provision in this Act or any Commission order, rule, or decision.
    For purposes of this Section, "distribution facilities and equipment" means any and all of the facilities and equipment, including, but not limited to, substations, distribution feeder circuits, switches, meters, protective equipment, primary circuits, distribution transformers, line extensions and service extensions both above or below ground, conduit, risers, elbows, transformer pads, junction boxes, manholes, pedestals, conductors, and all associated fittings that connect the transmission or distribution system to either the weatherhead on the retail customer's building or other structure for above ground service or to the terminals on the meter base of the retail customer's building or other structure for below ground service.
    To implement this requirement for alternative retail electric suppliers, the Commission, in determining that an applicant meets the standards for certification as an alternative retail electric supplier, shall require the applicant to demonstrate (i) that the applicant is licensed to do business, and bonded, in the State of Illinois; and (ii) that the employees of the applicant that will be installing, operating, and maintaining generation, transmission, or distribution facilities within this State, or any entity with which the applicant has contracted to perform those functions within this State, have the requisite knowledge, skills, training, experience, and competence to perform those functions in a safe and responsible manner in order to provide safe and reliable service, in accordance with the criteria stated above.
    (b) The General Assembly finds, based on experience in other industries that have undergone similar transitions, that the introduction of competition into the State's electric utility industry may result in workforce reductions by electric utilities which may adversely affect persons who have been employed by this State's electric utilities in functions important to the public convenience and welfare. The General Assembly further finds that the impacts on employees and their communities of any necessary reductions in the utility workforce directly caused by this restructuring of the electric industry shall be mitigated to the extent practicable through such means as offers of voluntary severance, retraining, early retirement, outplacement and related benefits. Therefore, before any such reduction in the workforce during the transition period, an electric utility shall present to its employees or their representatives a workforce reduction plan outlining the means by which the electric utility intends to mitigate the impact of such workforce reduction on its employees.
    (c) In the event of a sale, purchase, or any other transfer of ownership during the mandatory transition period of one or more Illinois divisions or business units, and/or generating stations or generating units, of an electric utility, the electric utility's contract and/or agreements with the acquiring entity or persons shall require that the entity or persons hire a sufficient number of non-supervisory employees to operate and maintain the station, division or unit by initially making offers of employment to the non-supervisory workforce of the electric utility's division, business unit, generating station and/or generating unit at no less than the wage rates, and substantially equivalent fringe benefits and terms and conditions of employment that are in effect at the time of transfer of ownership of said division, business unit, generating station, and/or generating units; and said wage rates and substantially equivalent fringe benefits and terms and conditions of employment shall continue for at least 30 months from the time of said transfer of ownership unless the parties mutually agree to different terms and conditions of employment within that 30-month period. The utility shall offer a transition plan to those employees who are not offered jobs by the acquiring entity because that entity has a need for fewer workers. If there is litigation concerning the sale, or other transfer of ownership of the electric utility's divisions, business units, generating station, or generating units, the 30-month period will begin on the date the acquiring entity or persons take control or management of the divisions, business units, generating station or generating units of the electric utility.
    (d) If a utility transfers ownership during the mandatory transition period of one or more Illinois divisions, business units, generating stations or generating units of an electric utility to a majority-owned subsidiary, that subsidiary shall continue to employ the utility's employees who were employed by the utility at such division, business unit or generating station at the time of the transfer under the same terms and conditions of employment as those employees enjoyed at the time of the transfer. If ownership of the subsidiary is subsequently sold or transferred to a third party during the transition period, the transition provisions outlined in subsection (c) shall apply.
    (e) The plant transfer provisions set forth above shall not apply to any generating station which was the subject of a sales agreement entered into before January 1, 1997.
(Source: P.A. 97-616, eff. 10-26-11; 97-646, eff. 12-30-11.)

    (220 ILCS 5/16-128A)
    Sec. 16-128A. Certification of installers, maintainers, or repairers.
    (a) Within 18 months of the effective date of this amendatory Act of the 97th General Assembly, the Commission shall adopt rules, including emergency rules, establishing certification requirements ensuring that entities installing distributed generation facilities are in compliance with the requirements of subsection (a) of Section 16-128 of this Act.
    For purposes of this Section, the phrase "entities installing distributed generation facilities" shall include, but not be limited to, all entities that are exempt from the definition of "alternative retail electric supplier" under item (v) of Section 16-102 of this Act. For purposes of this Section, the phrase "self-installer" means an individual who (i) leases or purchases a cogeneration facility for his or her own personal use and (ii) installs such cogeneration or self-generation facility on his or her own premises without the assistance of any other person.
    (b) In addition to any authority granted to the Commission under this Act, the Commission is also authorized to: (1) determine which entities are subject to certification under this Section; (2) impose reasonable certification fees and penalties; (3) adopt disciplinary procedures; (4) investigate any and all activities subject to this Section, including violations thereof; (5) adopt procedures to issue or renew, or to refuse to issue or renew, a certification or to revoke, suspend, place on probation, reprimand, or otherwise discipline a certified entity under this Act or take other enforcement action against an entity subject to this Section; and (6) prescribe forms to be issued for the administration and enforcement of this Section.
    (c) No electric utility shall provide a retail customer with net metering service related to interconnection of that customer's distributed generation facility unless the customer provides the electric utility with (i) a certification that the customer installing the distributed generation facility was a self-installer or (ii) evidence that the distributed generation facility was installed by an entity certified under this Section that is also in good standing with the Commission. For purposes of this subsection, a retail customer includes that customer's employees, officers, and agents. An electric utility shall file a tariff or tariffs with the Commission setting forth the documentation, as specified by Commission rule, that a retail customer must provide to an electric utility. The provisions of this subsection (c) shall apply on or after the effective date of the Commission's rules prescribed pursuant to subsection (a) of this Section.
    (d) Within 180 days after the effective date of this amendatory Act of the 97th General Assembly, the Commission shall initiate a rulemaking proceeding to establish certification requirements that shall be applicable to persons or entities that install, maintain, or repair electric vehicle charging stations. The notification and certification requirements of this Section shall only be applicable to individuals or entities that perform work on or within an electric vehicle charging station, including, but not limited to, connection of power to an electric vehicle charging station.
    For the purposes of this Section "electric vehicle charging station" means any facility or equipment that is used to charge a battery or other energy storage device of an electric vehicle.
    Rules regulating the installation, maintenance, or repair of electric vehicle charging stations, in which the Commission may establish separate requirements based upon the characteristics of electric vehicle charging stations, so long as it is in accordance with the requirements of subsection (a) of Section 16-128 and Section 16-128A of this Act, shall:
        (1) establish a certification process for persons or

    
entities that install, maintain, or repair of electric vehicle charging stations;
        (2) require persons or entities that install,
    
maintain, or repair electric vehicle stations to be certified to do business and to be bonded in the State;
        (3) ensure that persons or entities that install,
    
maintain, or repair electric vehicle charging stations have the requisite knowledge, skills, training, experience, and competence to perform functions in a safe and reliable manner as required under subsection (a) of Section 16-128 of this Act;
        (4) impose reasonable certification fees and
    
penalties on persons or entities that install, maintain, or repair of electric vehicle charging stations for noncompliance of the rules adopted under this subsection;
        (5) ensure that all persons or entities that install,
    
maintain, or repair electric vehicle charging stations conform to applicable building and electrical codes;
        (6) ensure that all electric vehicle charging
    
stations meet recognized industry standards as the Commission deems appropriate, such as the National Electric Code (NEC) and standards developed or created by the Institute of Electrical and Electronics Engineers (IEEE), the Electric Power Research Institute (EPRI), the Detroit Edison Institute (DTE), the Underwriters Laboratory (UL), the Society of Automotive Engineers (SAE), and the National Institute of Standards and Technology (NIST);
        (7) include any additional requirements that the
    
Commission deems reasonable to ensure that persons or entities that install, maintain, or repair electric vehicle charging stations meet adequate training, financial, and competency requirements;
        (8) ensure that the obligations required under this
    
Section and subsection (a) of Section 16-128 of this Act are met prior to the interconnection of any electric vehicle charging station;
        (9) ensure electric vehicle charging stations
    
installed by a self-installer are not used for any commercial purpose;
        (10) establish an inspection procedure for the
    
conversion of electric vehicle charging stations installed by a self-installer if it is determined that the self-installed electric vehicle charging station is being used for commercial purposes;
        (11) establish the requirement that all persons or
    
entities that install electric vehicle charging stations shall notify the servicing electric utility in writing of plans to install an electric vehicle charging station and shall notify the servicing electric utility in writing when installation is complete;
        (12) ensure that all persons or entities that
    
install, maintain, or repair electric vehicle charging stations obtain certificates of insurance in sufficient amounts and coverages that the Commission so determines and, if necessary as determined by the Commission, names the affected public utility as an additional insured; and
        (13) identify and determine the training or other
    
programs by which persons or entities may obtain the requisite training, skills, or experience necessary to achieve and maintain compliance with the requirements set forth in this subsection and subsection (a) of Section 16-128 to install, maintain, or repair electric vehicle charging stations.
    Within 18 months after the effective date of this amendatory Act of the 97th General Assembly, the Commission shall adopt rules, and may, if it deems necessary, adopt emergency rules, for the installation, maintenance, or repair of electric vehicle charging stations.
    All retail customers who own, maintain, or repair an electric vehicle charging station shall provide the servicing electric utility (i) a certification that the customer installing the electric vehicle charging station was a self-installer or (ii) evidence that the electric vehicle charging station was installed by an entity certified under this subsection (d) that is also in good standing with the Commission. For purposes of this subsection (d), a retail customer includes that retail customer's employees, officers, and agents. If the electric vehicle charging station was not installed by a self-installer, then the person or entity that plans to install the electric vehicle charging station shall provide notice to the servicing electric utility prior to installation and when installation is complete and provide any other information required by the Commission's rules established under subsection (d) of this Section. An electric utility shall file a tariff or tariffs with the Commission setting forth the documentation, as specified by Commission rule, that a retail customer who owns, uses, operates, or maintains an electric vehicle charging station must provide to an electric utility.
    For the purposes of this subsection, an electric vehicle charging station shall constitute a distribution facility or equipment as that term is used in subsection (a) of Section 16-128 of this Act. The phrase "self-installer" means an individual who (i) leases or purchases an electric vehicle charging station for his or her own personal use and (ii) installs an electric vehicle charging station on his or her own premises without the assistance of any other person.
    (e) Fees and penalties collected under this Section shall be deposited into the Public Utility Fund and used to fund the Commission's compliance with the obligations imposed by this Section.
    (f) The rules established under subsection (d) of this Section shall specify the initial dates for compliance with the rules.
    (g) The certification of persons or entities that install, maintain, or repair distributed generation facilities and electric vehicle charging stations as set forth in this Section is an exclusive power and function of the State. A home rule unit or other units of local government authority may subject persons or entities that install, maintain, or repair distributed generation facilities or electric vehicle charging stations as set forth in this Section to any applicable local licensing, siting, and permitting requirements otherwise permitted under law so long as only Commission-certified persons or entities are authorized to install, maintain, or repair distributed generation facilities or electric vehicle charging stations. This Section is a limitation under subsection (h) of Section 6 of Article VII of the Illinois Constitution on the exercise by home rule units of powers and functions exclusively exercised by the State.
(Source: P.A. 97-616, eff. 10-26-11; 97-1128, eff. 8-28-12.)

    (220 ILCS 5/16-129)
    Sec. 16-129. Existing contracts not affected. Nothing in this Article XVI shall affect the right of an electric utility to continue to provide, or the right of the customer to continue to receive, service pursuant to a contract for electric service between the electric utility and the customer, in accordance with the prices, terms and conditions provided for in that contract. Either the electric utility or the customer may require compliance with the prices, terms and conditions of such contract.
(Source: P.A. 90-561, eff. 12-16-97.)

    (220 ILCS 5/16-130)
    Sec. 16-130. Annual Reports. The General Assembly finds that it is necessary to have reliable and accurate information regarding the transition to a competitive electric industry. In addition to the annual report requirements pursuant to Section 5-109 of this Act, each electric utility shall file with the Commission a report on the following topics in accordance with the schedule set forth in subsection (b) of this Section:
        (1) Data on each customer class of the electric

    
utility in which delivery services have been elected including:
            (A) number of retail customers in each class that
        
have elected delivery service;
            (B) kilowatt hours consumed by the customers
        
described in subparagraph (A);
            (C) revenue loss experienced by the utility as a
        
result of customers electing delivery services or market-based prices as compared to continued service under otherwise applicable tariffed rates;
            (D) total amount of funds collected from each
        
customer class pursuant to the transition charges authorized in Section 16-108;
            (E) Such other information as the Commission may
        
by rule require.
        (2) A description of any steps taken by the electric
    
utility to mitigate and reduce its costs, including both a detailed description of steps taken during the preceding calendar year and a summary of steps taken since the effective date of this amendatory Act of 1997, and including, to the extent practicable, quantification of the costs mitigated or reduced by specific actions taken by the electric utility.
        (3) A description of actions taken under Sections
    
5-104, 7-204, 9-220, and 16-111 of this Act. This information shall include but not be limited to:
            (A) a description of the actions taken;
            (B) the effective date of the action;
            (C) the annual savings or additional charges
        
realized by customers from actions taken, by customer class and total for each year;
            (D) the accumulated impact on customers by
        
customer class and total; and
            (E) a summary of the method used to quantify the
        
impact on customers.
        (4) A summary of the electric utility's use of
    
transitional funding instruments, including a description of the electric utility's use of the proceeds of any transitional funding instruments it has issued in accordance with Article XVIII of this Act.
        (5) Kilowatt-hours consumed in the twelve months
    
ending December 31, 1996 (which kilowatt-hours are hereby referred to as "base year sales") by customer class multiplied by the revenue per kilowatt hour, adjusted to remove charges added to customers' bills pursuant to Sections 9-221 and 9-222 of this Act, during the twelve months ending December 31, 1996, adjusted for the reductions required by subsection (b) of Section 16-111 and the mitigation factors contained in Section 16-102. This amount shall be stated for: (i) each calendar year preceding the year in which a report is required to be submitted pursuant to subsection (b); and (ii) as a cumulative total of all calendar years beginning with 1998 and ending with the calendar year preceding the year in which a report is required to be submitted pursuant to subsection (b).
        (6) Calculations identical to those required by
    
subparagraph (5) except that base year sales shall be adjusted for growth in the electric utility's service territory, in addition to the other adjustments specified by the first sentence of subparagraph (5).
        (7) The electric utility's total revenue and net
    
income for each calendar year beginning with 1997 through the calendar year preceding the year in which a report is required to be submitted pursuant to subsection (b) as reported in the electric utility's Form 1 report to the Federal Energy Regulatory Commission.
        (8) Any consideration in excess of the net book cost
    
as of the effective date of this amendatory Act of 1997 received by the electric utility during the year from a sale made subsequent to the effective date of this amendatory Act of 1997 to a non-affiliated third party of any generating plant that was owned by the electric utility on the effective date of this amendatory Act of 1997.
        (9) Any consideration received by the electric
    
utility from sales or transfers during the year to an affiliated interest of generating plant, or other plant that represents an investment of $25,000,000 or more in terms of total depreciated original cost, which generating or other plant were owned by the electric utility prior to the effective date of this amendatory Act of 1997.
        (10) Any consideration received by an affiliated
    
interest of an electric utility from sales or transfers during the year to a non-affiliated third party of generating plant, but only if: (i) the electric utility had previously sold or transferred such plant to the affiliated interest subsequent to the effective date of this amendatory Act of 1997; (ii) the affiliated interest sells or transfers such plant to a non-affiliated third party prior to December 31, 2006; and (iii) the affiliated interest receives consideration for the sale or transfer of such plant to the non-affiliated third party in an amount greater than the cost or price at which such plant was sold or transferred to the affiliated interest by the electric utility.
        (11) A summary account of those expenditures made for
    
projects, programs, and improvements relating to transmission and distribution including, without limitation, infrastructure expansion, repair and replacement, capital investments, operations and maintenance, and vegetation management, pursuant to a written commitment made under subsection (k) of Section 16-111.
    (b) The information required by subsection (a) shall be filed by each electric utility on or before March 1 of each year 1999 through 2007 or through such additional years as the electric utility is collecting transition charges pursuant to subsection (f) of Section 16-108, for the previous calendar year. The information required by subparagraph (6) of subsection (a) for calendar year 1997 shall be submitted by the electric utility on or before March 1, 1999.
    (c) On or before May 15 of each year 1999 through 2006 or through such additional years as the electric utility is collecting transition charges pursuant to subsection (f) of Section 16-108, the Commission shall submit a report to the General Assembly which summarizes the information provided by each electric utility under this Section; provided, however, that proprietary or confidential information shall not be publicly disclosed.
(Source: P.A. 90-561, eff. 12-16-97; 91-50, eff. 6-30-99.)