HB0690ham001 97TH GENERAL ASSEMBLY

Rep. Kevin A. McCarthy

Filed: 10/25/2011

09700HB0690ham001 LRB097 03518 CEL 59067 a

AMENDMENT TO HOUSE BILL 690

AMENDMENT NO. ______. Amend House Bill 690 by replacing everything after the enacting clause with the following:

"Section 1. Findings. The General Assembly finds that:

(1) subsection (b-10) of Section 16-108.5 of this amendatory Act of the 97th General Assembly provides substantial customer assistance programs for low-income customers, senior citizens, active members of the armed services and reserved forces, and disabled veterans;

(2) subsection (b) of Section 16-108.5 of this amendatory Act of the 97th General Assembly provides for infrastructure improvements designed to reduce outages due to storms;

(3) subsections (f) and (f-5) of Section 16-108.5 of this amendatory Act of the 97th General Assembly require improvement in a variety of performance metrics and impose penalties on the electric utilities for failure to achieve the statutorily set goals;

(4) Black & Veatch, a global engineering, consulting and construction company, performed an independent evaluation of Commonwealth Edison Company's Advanced Metering Infrastructure ("AMI") pilot program and concluded that the cost savings and benefits to ComEd customers of full AMI deployment are nearly 3 times greater than the cost to deploy AMI, and further that AMI deployment is estimated to result in a net savings to ComEd customers of $2.8 billion over 20 years; and

(5) this amendatory Act of the 97th General Assembly confers substantial benefits upon the State's electric utility customers.

Section 5. If and only if Senate Bill 1652 of the 97th General Assembly becomes law, then the Public Utilities Act is amended by changing Section 16-107.5, 16-108.5, 16-108.6, 16-108.7, and 16-128 as follows:

(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 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 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 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 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 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, provided that 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) 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 whose electric service has not been declared competitive pursuant to Section 16-113 of this Act and whose electric supply service is not provided based on hourly pricing 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. 95-420, eff. 8-24-07; 09700SB1652enr.)

(220 ILCS 5/16-108.5)

Sec. 16-108.5. Infrastructure investment and modernization; regulatory reform.

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

The General Assembly further recognizes that, in addition to attracting capital and businesses to the State, these investments will create training opportunities for the citizens of this State, all of which will create new employment opportunities for Illinoisans at a time when they are most needed, especially for minority-owned and female-owned business enterprises. The General Assembly further finds that regulatory reform measures that increase predictability, stability, and transparency in the ratemaking process are needed to promote prudent, long-term infrastructure investment and to mutually benefit the State's electric utilities and their customers, regulators, and investors.

(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 , including 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 $1,100,000,000 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; and

(iii) wood pole inspection, treatment, and replacement programs; and

(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 $1,500,000,000 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 $3,000 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 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) 580 600 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 on pension assets net of deferred tax benefits equal to the utility's long-term debt cost of capital as of the end of the applicable calendar year;

(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, with interest as described in subsection (d) of this Section, 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 (as 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, 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 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 approved by the Commission in such order or orders in effect during that year (weighted, as applicable). 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 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) paragraph (C), 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) (3) 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) (3) 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; for such unachieved goal for the following 12-month period, 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 for each such unachieved goal for the following 12-month period.

(2) With respect to each of the incremental annual performance goals established pursuant to paragraph subparagraphs (2), (3), and (4) of subsection (f) of this Section, as applicable, 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 for each such unachieved goal for the following 12-month period.

(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 for the following 12-month period.

(6) (3) 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 for the following 12-month period.

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.

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.

(Source: 09700SB1652enr.)

(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 7 total voting members with each member possessing either technical, business or consumer expertise in Smart Grid issues, 5 of whom shall be appointed by and each having been the single appointment of one of the following: 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; (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 Illinois Science and Technology Coalition, and the Citizens Utility Board.

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: 09700SB1652enr.)

(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 7 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: 09700SB1652enr.)

(220 ILCS 5/16-128)

Sec. 16-128. Provisions related to utility employees during the mandatory transition period.

(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. 90-561, eff. 12-16-97; 09700SB1652enr.)

Section 99. Effective date. This Act takes effect upon becoming law.".