SB1665 98TH GENERAL ASSEMBLY

LRB098 07846 JLS 40702 b

98TH GENERAL ASSEMBLY
State of Illinois
2013 and 2014
SB1665

Introduced 2/13/2013, by Sen. David Koehler

SYNOPSIS AS INTRODUCED:

220 ILCS 5/9-220	from Ch. 111 2/3, par. 9-220
220 ILCS 5/9-244.5 new
220 ILCS 5/19-150.6 new

Amends the Public Utilities Act. Provides that certain gas natural utilities may recover expenditures made in relation to infrastructure modernization. Authorizes rates to be established on performance-based manner. Provides for customer assistance programs. Sets job creation and infrastructure modernization criteria. Authorizes recovery of delivery costs under a performance-based formula including incentive compensation expenses, pension expenses, and severance expenses. Provides for the deployment of advanced gas metering. Effective immediately.

FISCAL NOTE ACT MAY APPLY

A BILL FOR

AN ACT concerning regulation.

Be it enacted by the People of the State of Illinois, represented in the General Assembly:

Section 5. The Public Utilities Act is amended by changing Section 9-220 and by adding Sections 9-244.5 and 19-150.6 as follows:

(220 ILCS 5/9-220) (from Ch. 111 2/3, par. 9-220)

Sec. 9-220. Rate changes based on changes in fuel costs.

(a) Notwithstanding the provisions of Section 9-201, the Commission may authorize the increase or decrease of rates and charges based upon changes in the cost of fuel used in the generation or production of electric power, changes in the cost of purchased power, or changes in the cost of purchased gas through the application of fuel adjustment clauses or purchased gas adjustment clauses. The Commission may also authorize the increase or decrease of rates and charges based upon expenditures or revenues resulting from the purchase or sale of emission allowances created under the federal Clean Air Act Amendments of 1990, through such fuel adjustment clauses, as a cost of fuel. For the purposes of this paragraph, cost of fuel used in the generation or production of electric power shall include the amount of any fees paid by the utility for the implementation and operation of a process for the desulfurization of the flue gas when burning high sulfur coal at any location within the State of Illinois irrespective of the attainment status designation of such location; but shall not include transportation costs of coal (i) except to the extent that for contracts entered into on and after the effective date of this amendatory Act of 1997, the cost of the coal, including transportation costs, constitutes the lowest cost for adequate and reliable fuel supply reasonably available to the public utility in comparison to the cost, including transportation costs, of other adequate and reliable sources of fuel supply reasonably available to the public utility, or (ii) except as otherwise provided in the next 3 sentences of this paragraph. Such costs of fuel shall, when requested by a utility or at the conclusion of the utility's next general electric rate proceeding, whichever shall first occur, include transportation costs of coal purchased under existing coal purchase contracts. For purposes of this paragraph "existing coal purchase contracts" means contracts for the purchase of coal in effect on the effective date of this amendatory Act of 1991, as such contracts may thereafter be amended, but only to the extent that any such amendment does not increase the aggregate quantity of coal to be purchased under such contract. Nothing herein shall authorize an electric utility to recover through its fuel adjustment clause any amounts of transportation costs of coal that were included in the revenue requirement used to set base rates in its most recent general rate proceeding. Cost shall be based upon uniformly applied accounting principles. Annually, the Commission shall initiate public hearings to determine whether the clauses reflect actual costs of fuel, gas, power, or coal transportation purchased to determine whether such purchases were prudent, and to reconcile any amounts collected with the actual costs of fuel, power, gas, or coal transportation prudently purchased. In each such proceeding, the burden of proof shall be upon the utility to establish the prudence of its cost of fuel, power, gas, or coal transportation purchases and costs. The Commission shall issue its final order in each such annual proceeding for an electric utility by December 31 of the year immediately following the year to which the proceeding pertains, provided, that the Commission shall issue its final order with respect to such annual proceeding for the years 1996 and earlier by December 31, 1998.

(b) A public utility providing electric service, other than a public utility described in subsections (e) or (f) of this Section, may at any time during the mandatory transition period file with the Commission proposed tariff sheets that eliminate the public utility's fuel adjustment clause and adjust the public utility's base rate tariffs by the amount necessary for the base fuel component of the base rates to recover the public utility's average fuel and power supply costs per kilowatt-hour for the 2 most recent years for which the Commission has issued final orders in annual proceedings pursuant to subsection (a), where the average fuel and power supply costs per kilowatt-hour shall be calculated as the sum of the public utility's prudent and allowable fuel and power supply costs as found by the Commission in the 2 proceedings divided by the public utility's actual jurisdictional kilowatt-hour sales for those 2 years. Notwithstanding any contrary or inconsistent provisions in Section 9-201 of this Act, in subsection (a) of this Section or in any rules or regulations promulgated by the Commission pursuant to subsection (g) of this Section, the Commission shall review and shall by order approve, or approve as modified, the proposed tariff sheets within 60 days after the date of the public utility's filing. The Commission may modify the public utility's proposed tariff sheets only to the extent the Commission finds necessary to achieve conformance to the requirements of this subsection (b). During the 5 years following the date of the Commission's order, but in any event no earlier than January 1, 2007, a public utility whose fuel adjustment clause has been eliminated pursuant to this subsection shall not file proposed tariff sheets seeking, or otherwise petition the Commission for, reinstatement of a fuel adjustment clause.

(c) Notwithstanding any contrary or inconsistent provisions in Section 9-201 of this Act, in subsection (a) of this Section or in any rules or regulations promulgated by the Commission pursuant to subsection (g) of this Section, a public utility providing electric service, other than a public utility described in subsection (e) or (f) of this Section, may at any time during the mandatory transition period file with the Commission proposed tariff sheets that establish the rate per kilowatt-hour to be applied pursuant to the public utility's fuel adjustment clause at the average value for such rate during the preceding 24 months, provided that such average rate results in a credit to customers' bills, without making any revisions to the public utility's base rate tariffs. The proposed tariff sheets shall establish the fuel adjustment rate for a specific time period of at least 3 years but not more than 5 years, provided that the terms and conditions for any reinstatement earlier than 5 years shall be set forth in the proposed tariff sheets and subject to modification or approval by the Commission. The Commission shall review and shall by order approve the proposed tariff sheets if it finds that the requirements of this subsection are met. The Commission shall not conduct the annual hearings specified in the last 3 sentences of subsection (a) of this Section for the utility for the period that the factor established pursuant to this subsection is in effect.

(d) A public utility providing electric service, or a public utility providing gas service may file with the Commission proposed tariff sheets that eliminate the public utility's fuel or purchased gas adjustment clause and adjust the public utility's base rate tariffs to provide for recovery of power supply costs or gas supply costs that would have been recovered through such clause; provided, that the provisions of this subsection (d) shall not be available to a public utility described in subsections (e) or (f) of this Section to eliminate its fuel adjustment clause. Notwithstanding any contrary or inconsistent provisions in Section 9-201 of this Act, in subsection (a) of this Section, or in any rules or regulations promulgated by the Commission pursuant to subsection (g) of this Section, the Commission shall review and shall by order approve, or approve as modified in the Commission's order, the proposed tariff sheets within 240 days after the date of the public utility's filing. The Commission's order shall approve rates and charges that the Commission, based on information in the public utility's filing or on the record if a hearing is held by the Commission, finds will recover the reasonable, prudent and necessary jurisdictional power supply costs or gas supply costs incurred or to be incurred by the public utility during a 12 month period found by the Commission to be appropriate for these purposes, provided, that such period shall be either (i) a 12 month historical period occurring during the 15 months ending on the date of the public utility's filing, or (ii) a 12 month future period ending no later than 15 months following the date of the public utility's filing. The public utility shall include with its tariff filing information showing both (1) its actual jurisdictional power supply costs or gas supply costs for a 12 month historical period conforming to (i) above and (2) its projected jurisdictional power supply costs or gas supply costs for a future 12 month period conforming to (ii) above. If the Commission's order requires modifications in the tariff sheets filed by the public utility, the public utility shall have 7 days following the date of the order to notify the Commission whether the public utility will implement the modified tariffs or elect to continue its fuel or purchased gas adjustment clause in force as though no order had been entered. The Commission's order shall provide for any reconciliation of power supply costs or gas supply costs, as the case may be, and associated revenues through the date that the public utility's fuel or purchased gas adjustment clause is eliminated. During the 5 years following the date of the Commission's order, a public utility whose fuel or purchased gas adjustment clause has been eliminated pursuant to this subsection shall not file proposed tariff sheets seeking, or otherwise petition the Commission for, reinstatement or adoption of a fuel or purchased gas adjustment clause. Nothing in this subsection (d) shall be construed as limiting the Commission's authority to eliminate a public utility's fuel adjustment clause or purchased gas adjustment clause in accordance with any other applicable provisions of this Act.

(e) Notwithstanding any contrary or inconsistent provisions in Section 9-201 of this Act, in subsection (a) of this Section, or in any rules promulgated by the Commission pursuant to subsection (g) of this Section, a public utility providing electric service to more than 1,000,000 customers in this State may, within the first 6 months after the effective date of this amendatory Act of 1997, file with the Commission proposed tariff sheets that eliminate, effective January 1, 1997, the public utility's fuel adjustment clause without adjusting its base rates, and such tariff sheets shall be effective upon filing. To the extent the application of the fuel adjustment clause had resulted in net charges to customers after January 1, 1997, the utility shall also file a tariff sheet that provides for a refund stated on a per kilowatt-hour basis of such charges over a period not to exceed 6 months; provided however, that such refund shall not include the proportional amounts of taxes paid under the Use Tax Act, Service Use Tax Act, Service Occupation Tax Act, and Retailers' Occupation Tax Act on fuel used in generation. The Commission shall issue an order within 45 days after the date of the public utility's filing approving or approving as modified such tariff sheet. If the fuel adjustment clause is eliminated pursuant to this subsection, the Commission shall not conduct the annual hearings specified in the last 3 sentences of subsection (a) of this Section for the utility for any period after December 31, 1996 and prior to any reinstatement of such clause. A public utility whose fuel adjustment clause has been eliminated pursuant to this subsection shall not file a proposed tariff sheet seeking, or otherwise petition the Commission for, reinstatement of the fuel adjustment clause prior to January 1, 2007.

(f) Notwithstanding any contrary or inconsistent provisions in Section 9-201 of this Act, in subsection (a) of this Section, or in any rules or regulations promulgated by the Commission pursuant to subsection (g) of this Section, a public utility providing electric service to more than 500,000 customers but fewer than 1,000,000 customers in this State may, within the first 6 months after the effective date of this amendatory Act of 1997, file with the Commission proposed tariff sheets that eliminate, effective January 1, 1997, the public utility's fuel adjustment clause and adjust its base rates by the amount necessary for the base fuel component of the base rates to recover 91% of the public utility's average fuel and power supply costs for the 2 most recent years for which the Commission, as of January 1, 1997, has issued final orders in annual proceedings pursuant to subsection (a), where the average fuel and power supply costs per kilowatt-hour shall be calculated as the sum of the public utility's prudent and allowable fuel and power supply costs as found by the Commission in the 2 proceedings divided by the public utility's actual jurisdictional kilowatt-hour sales for those 2 years, provided, that such tariff sheets shall be effective upon filing. To the extent the application of the fuel adjustment clause had resulted in net charges to customers after January 1, 1997, the utility shall also file a tariff sheet that provides for a refund stated on a per kilowatt-hour basis of such charges over a period not to exceed 6 months. Provided however, that such refund shall not include the proportional amounts of taxes paid under the Use Tax Act, Service Use Tax Act, Service Occupation Tax Act, and Retailers' Occupation Tax Act on fuel used in generation. The Commission shall issue an order within 45 days after the date of the public utility's filing approving or approving as modified such tariff sheet. If the fuel adjustment clause is eliminated pursuant to this subsection, the Commission shall not conduct the annual hearings specified in the last 3 sentences of subsection (a) of this Section for the utility for any period after December 31, 1996 and prior to any reinstatement of such clause. A public utility whose fuel adjustment clause has been eliminated pursuant to this subsection shall not file a proposed tariff sheet seeking, or otherwise petition the Commission for, reinstatement of the fuel adjustment clause prior to January 1, 2007.

(g) The Commission shall have authority to promulgate rules and regulations to carry out the provisions of this Section.

(h) Any Illinois gas utility may enter into a contract on or before September 30, 2011 for up to 10 years of supply with any company for the purchase of substitute natural gas (SNG) produced from coal through the gasification process if the company has commenced construction of a clean coal SNG facility by July 1, 2012 and commencement of construction shall mean that material physical site work has occurred, such as site clearing and excavation, water runoff prevention, water retention reservoir preparation, or foundation development. The contract shall contain the following provisions: (i) at least 90% of feedstock to be used in the gasification process shall be coal with a high volatile bituminous rank and greater than 1.7 pounds of sulfur per million Btu content; (ii) at the time the contract term commences, the price per million Btu may not exceed $7.95 in 2008 dollars, adjusted annually based on the change in the Annual Consumer Price Index for All Urban Consumers for the Midwest Region as published in April by the United States Department of Labor, Bureau of Labor Statistics (or a suitable Consumer Price Index calculation if this Consumer Price Index is not available) for the previous calendar year; provided that the price per million Btu shall not exceed $9.95 at any time during the contract; (iii) the utility's supply contract for the purchase of SNG does not exceed 15% of the annual system supply requirements of the utility as of 2008; and (iv) the contract costs pursuant to subsection (h-10) of this Section shall not include any lobbying expenses, charitable contributions, advertising, organizational memberships, carbon dioxide pipeline or sequestration expenses, or marketing expenses.

Any gas utility that is providing service to more than 150,000 customers on August 2, 2011 (the effective date of Public Act 97-239) shall either elect to enter into a contract on or before September 30, 2011 for 10 years of SNG supply with the owner of a clean coal SNG facility or to file biennial rate proceedings before the Commission in the years 2012, 2014, and 2016, with such filings made after August 2, 2011 and no later than September 30 of the years 2012, 2014, and 2016 consistent with all requirements of 83 Ill. Adm. Code 255 and 285 as though the gas utility were filing for an increase in its rates, without regard to whether such filing would produce an increase, a decrease, or no change in the gas utility's rates, and the Commission shall review the gas utility's filing and shall issue its order in accordance with the provisions of Section 9-201 of this Act; provided, however, that a gas utility having performance-based rates in effect pursuant to Section 9-244.5 of this Act that previously elected to make rate filings under this Section shall have no obligation to make such filings while such performance-based rates are in effect and the gas utility may withdraw, and the Commission shall approve any such request to withdraw, any pending rate filing at any time after it files to implement performance-based rates pursuant to Section 9-244.5.

Within 7 days after August 2, 2011, the owner of the clean coal SNG facility shall submit to the Illinois Power Agency and each gas utility that is providing service to more than 150,000 customers on August 2, 2011 a copy of a draft contract. Within 30 days after the receipt of the draft contract, each such gas utility shall provide the Illinois Power Agency and the owner of the clean coal SNG facility with its comments and recommended revisions to the draft contract. Within 7 days after the receipt of the gas utility's comments and recommended revisions, the owner of the facility shall submit its responsive comments and a further revised draft of the contract to the Illinois Power Agency. The Illinois Power Agency shall review the draft contract and comments.

During its review of the draft contract, the Illinois Power Agency shall:

(1) review and confirm in writing that the terms stated in this subsection (h) are incorporated in the SNG contract;

(2) review the SNG pricing formula included in the contract and approve that formula if the Illinois Power Agency determines that the formula, at the time the contract term commences: (A) starts with a price of $6.50 per MMBtu adjusted by the adjusted final capitalized plant cost; (B) takes into account budgeted miscellaneous net revenue after cost allowance, including sale of SNG produced by the clean coal SNG facility above the nameplate capacity of the facility and other by-products produced by the facility, as approved by the Illinois Power Agency; (C) does not include carbon dioxide transportation or sequestration expenses; and (D) includes all provisions required under this subsection (h); if the Illinois Power Agency does not approve of the SNG pricing formula, then the Illinois Power Agency shall modify the formula to ensure that it meets the requirements of this subsection (h);

(3) review and approve the amount of budgeted miscellaneous net revenue after cost allowance, including sale of SNG produced by the clean coal SNG facility above the nameplate capacity of the facility and other by-products produced by the facility, to be included in the pricing formula; the Illinois Power Agency shall approve the amount of budgeted miscellaneous net revenue to be included in the pricing formula if it determines the budgeted amount to be reasonable and accurate;

(4) review and confirm in writing that using the EIA Annual Energy Outlook-2011 Henry Hub Spot Price, the contract terms set out in subsection (h), the reconciliation account terms as set out in subsection (h-15), and an estimated inflation rate of 2.5% for each corresponding year, that there will be no cumulative estimated increase for residential customers; and

(5) allocate the nameplate capacity of the clean coal SNG by total therms sold to ultimate customers by each gas utility in 2008; provided, however, no utility shall be required to purchase more than 42% of the projected annual output of the facility; additionally, the Illinois Power Agency shall further adjust the allocation only as required to take into account (A) adverse consolidation, derivative, or lease impacts to the balance sheet or income statement of any gas utility or (B) the physical capacity of the gas utility to accept SNG.

If the parties to the contract do not agree on the terms therein, then the Illinois Power Agency shall retain an independent mediator to mediate the dispute between the parties. If the parties are in agreement on the terms of the contract, then the Illinois Power Agency shall approve the contract. If after mediation the parties have failed to come to agreement, then the Illinois Power Agency shall revise the draft contract as necessary to confirm that the contract contains only terms that are reasonable and equitable. The Illinois Power Agency may, in its discretion, retain an independent, qualified, and experienced expert to assist in its obligations under this subsection (h). The Illinois Power Agency shall adopt and make public policies detailing the processes for retaining a mediator and an expert under this subsection (h). Any mediator or expert retained under this subsection (h) shall be retained no later than 60 days after August 2, 2011.

The Illinois Power Agency shall complete all of its responsibilities under this subsection (h) within 60 days after August 2, 2011. The clean coal SNG facility shall pay a reasonable fee as required by the Illinois Power Agency for its services under this subsection (h) and shall pay the mediator's and expert's reasonable fees, if any. A gas utility and its customers shall have no obligation to reimburse the clean coal SNG facility or the Illinois Power Agency of any such costs.

Within 30 days after commercial production of SNG has begun, the Commission shall initiate a review to determine whether the final capitalized plant cost of the clean coal SNG facility reflects actual incurred costs and whether the incurred costs were reasonable. In determining the actual incurred costs included in the final capitalized plant cost and the reasonableness of those costs, the Commission may in its discretion retain independent, qualified, and experienced experts to assist in its determination. The expert shall not own or control any direct or indirect interest in the clean coal SNG facility and shall have no contractual relationship with the clean coal SNG facility. If an expert is retained by the Commission, then the clean coal SNG facility shall pay the expert's reasonable fees. The fees shall not be passed on to a utility or its customers. The Commission shall adopt and make public a policy detailing the process for retaining experts under this subsection (h).

Within 30 days after completion of its review, the Commission shall initiate a formal proceeding on the final capitalized plant cost of the clean coal SNG facility at which comments and testimony may be submitted by any interested parties and the public. If the Commission finds that the final capitalized plant cost includes costs that were not actually incurred or costs that were unreasonably incurred, then the Commission shall disallow the amount of non-incurred or unreasonable costs from the SNG price under contracts entered into under this subsection (h). If the Commission disallows any costs, then the Commission shall adjust the SNG price using the price formula in the contract approved by the Illinois Power Agency under this subsection (h) to reflect the disallowed costs and shall enter an order specifying the revised price. In addition, the Commission's order shall direct the clean coal SNG facility to issue refunds of such sums as shall represent the difference between actual gross revenues and the gross revenue that would have been obtained based upon the same volume, from the price revised by the Commission. Any refund shall include interest calculated at a rate determined by the Commission and shall be returned according to procedures prescribed by the Commission.

Nothing in this subsection (h) shall preclude any party affected by a decision of the Commission under this subsection (h) from seeking judicial review of the Commission's decision.

(h-1) Any Illinois gas utility may enter into a sourcing agreement for up to 30 years of supply with the clean coal SNG brownfield facility if the clean coal SNG brownfield facility has commenced construction. Any gas utility that is providing service to more than 150,000 customers on July 13, 2011 (the effective date of Public Act 97-096) shall either elect to file biennial rate proceedings before the Commission in the years 2012, 2014, and 2016 or enter into a sourcing agreement or sourcing agreements with a clean coal SNG brownfield facility with an initial term of 30 years for either (i) a percentage of 43,500,000,000 cubic feet per year, such that the utilities entering into sourcing agreements with the clean coal SNG brownfield facility purchase 100%, allocated by total therms sold to ultimate customers by each gas utility in 2008 or (ii) such lesser amount as may be available from the clean coal SNG brownfield facility; provided that no utility shall be required to purchase more than 42% of the projected annual output of the clean coal SNG brownfield facility, with the remainder of such utility's obligation to be divided proportionately between the other utilities, and provided that the Illinois Power Agency shall further adjust the allocation only as required to take into account adverse consolidation, derivative, or lease impacts to the balance sheet or income statement of any gas utility.

A gas utility electing to file biennial rate proceedings before the Commission must file a notice of its election with the Commission within 60 days after July 13, 2011 or its right to make the election is irrevocably waived. A gas utility electing to file biennial rate proceedings shall make such filings no later than August 1 of the years 2012, 2014, and 2016, consistent with all requirements of 83 Ill. Adm. Code 255 and 285 as though the gas utility were filing for an increase in its rates, without regard to whether such filing would produce an increase, a decrease, or no change in the gas utility's rates, and notwithstanding any other provisions of this Act, the Commission shall fully review the gas utility's filing and shall issue its order in accordance with the provisions of Section 9-201 of this Act, provided, however, that a gas utility having performance-based rates in effect pursuant to Section 9-244.5 of this Act that previously elected to make rate filings under this Section shall have no obligation to make such filings while such performance-based rates are in effect and the gas utility may withdraw, and the Commission shall approve any such request to withdraw, any pending rate filing at any time after it files to implement performance-based rates pursuant to Section 9-244.5 regardless of whether the Commission has approved a formula rate for the gas utility.

Within 15 days after July 13, 2011, the owner of the clean coal SNG brownfield facility shall submit to the Illinois Power Agency and each gas utility that is providing service to more than 150,000 customers on July 13, 2011 a copy of a draft sourcing agreement. Within 45 days after receipt of the draft sourcing agreement, each such gas utility shall provide the Illinois Power Agency and the owner of a clean coal SNG brownfield facility with its comments and recommended revisions to the draft sourcing agreement. Within 15 days after the receipt of the gas utility's comments and recommended revisions, the owner of the clean coal SNG brownfield facility shall submit its responsive comments and a further revised draft of the sourcing agreement to the Illinois Power Agency. The Illinois Power Agency shall review the draft sourcing agreement and comments.

If the parties to the sourcing agreement do not agree on the terms therein, then the Illinois Power Agency shall retain an independent mediator to mediate the dispute between the parties. If the parties are in agreement on the terms of the sourcing agreement, the Illinois Power Agency shall approve the final draft sourcing agreement. If after mediation the parties have failed to come to agreement, then the Illinois Power Agency shall revise the draft sourcing agreement as necessary to confirm that the final draft sourcing agreement contains only terms that are reasonable and equitable. The Illinois Power Agency shall adopt and make public a policy detailing the process for retaining a mediator under this subsection (h-1). Any mediator retained to assist with mediating disputes between the parties regarding the sourcing agreement shall be retained no later than 60 days after July 13, 2011.

Upon approval of a final draft agreement, the Illinois Power Agency shall submit the final draft agreement to the Capital Development Board and the Commission no later than 90 days after July 13, 2011. The gas utility and the clean coal SNG brownfield facility shall pay a reasonable fee as required by the Illinois Power Agency for its services under this subsection (h-1) and shall pay the mediator's reasonable fees, if any. The Illinois Power Agency shall adopt and make public a policy detailing the process for retaining a mediator under this Section.

The sourcing agreement between a gas utility and the clean coal SNG brownfield facility shall contain the following provisions:

(1) Any and all coal used in the gasification process must be coal that has high volatile bituminous rank and greater than 1.7 pounds of sulfur per million Btu content.

(2) Coal and petroleum coke are feedstocks for the gasification process, with coal comprising at least 50% of the total feedstock over the term of the sourcing agreement unless the facility reasonably determines that it is necessary to use additional petroleum coke to deliver net consumer savings, in which case the facility shall use coal for at least 35% of the total feedstock over the term of any sourcing agreement and with the feedstocks to be procured in accordance with requirements of Section 1-78 of the Illinois Power Agency Act.

(3) The sourcing agreement has an initial term that once entered into terminates no more than 30 years after the commencement of the commercial production of SNG at the clean coal SNG brownfield facility.

(4) The clean coal SNG brownfield facility guarantees a minimum of $100,000,000 in consumer savings to customers of the utilities that have entered into sourcing agreements with the clean coal SNG brownfield facility, calculated in real 2010 dollars at the conclusion of the term of the sourcing agreement by comparing the delivered SNG price to the Chicago City-gate price on a weighted daily basis for each day over the entire term of the sourcing agreement, to be provided in accordance with subsection (h-2) of this Section.

(5) Prior to the clean coal SNG brownfield facility issuing a notice to proceed to construction, the clean coal SNG brownfield facility shall establish a consumer protection reserve account for the benefit of the customers of the utilities that have entered into sourcing agreements with the clean coal SNG brownfield facility pursuant to this subsection (h-1), with cash principal in the amount of $150,000,000. This cash principal shall only be recoverable through the consumer protection reserve account and not as a cost to be recovered in the delivered SNG price pursuant to subsection (h-3) of this Section. The consumer protection reserve account shall be maintained and administered by an independent trustee that is mutually agreed upon by the clean coal SNG brownfield facility, the utilities, and the Commission in an interest-bearing account in accordance with subsection (h-2) of this Section.

"Consumer protection reserve account principal maximum amount" shall mean the maximum amount of principal to be maintained in the consumer protection reserve account. During the first 2 years of operation of the facility, there shall be no consumer protection reserve account maximum amount. After the first 2 years of operation of the facility, the consumer protection reserve account maximum amount shall be $150,000,000. After 5 years of operation, and every 5 years thereafter, the trustee shall calculate the 5-year average balance of the consumer protection reserve account. If the trustee determines that during the prior 5 years the consumer protection reserve account has had an average account balance of less than $75,000,000, then the consumer protection reserve account principal maximum amount shall be increased by $5,000,000. If the trustee determines that during the prior 5 years the consumer protection reserve account has had an average account balance of more than $75,000,000, then the consumer protection reserve account principal maximum amount shall be decreased by $5,000,000.

(6) The clean coal SNG brownfield facility shall identify and sell economically viable by-products produced by the facility.

(7) Fifty percent of all additional net revenue, defined as miscellaneous net revenue from products produced by the facility and delivered during the month after cost allowance for costs associated with additional net revenue that are not otherwise recoverable pursuant to subsection (h-3) of this Section, including net revenue from sales of substitute natural gas derived from the facility above the nameplate capacity of the facility and other by-products produced by the facility, shall be credited to the consumer protection reserve account pursuant to subsection (h-2) of this Section.

(8) The delivered SNG price per million btu to be paid monthly by the utility to the clean coal SNG brownfield facility, which shall be based only upon the following: (A) a capital recovery charge, operations and maintenance costs, and sequestration costs, only to the extent approved by the Commission pursuant to paragraphs (1), (2), and (3) of subsection (h-3) of this Section; (B) the actual delivered and processed fuel costs pursuant to paragraph (4) of subsection (h-3) of this Section; (C) actual costs of SNG transportation pursuant to paragraph (6) of subsection (h-3) of this Section; (D) certain taxes and fees imposed by the federal government, the State, or any unit of local government as provided in paragraph (6) of subsection (h-3) of this Section; and (E) the credit, if any, from the consumer protection reserve account pursuant to subsection (h-2) of this Section. The delivered SNG price per million Btu shall proportionately reflect these elements over the term of the sourcing agreement.

(9) A formula to translate the recoverable costs and charges under subsection (h-3) of this Section into the delivered SNG price per million btu.

(10) Title to the SNG shall pass at a mutually agreeable point in Illinois, and may provide that, rather than the utility taking title to the SNG, a mutually agreed upon third-party gas marketer pursuant to a contract approved by the Illinois Power Agency or its designee may take title to the SNG pursuant to an agreement between the utility, the owner of the clean coal SNG brownfield facility, and the third-party gas marketer.

(11) A utility may exit the sourcing agreement without penalty if the clean coal SNG brownfield facility does not commence construction by July 1, 2015.

(12) A utility is responsible to pay only the Commission determined unit price cost of SNG that is purchased by the utility. Nothing in the sourcing agreement will obligate a utility to invest capital in a clean coal SNG brownfield facility.

(13) The quality of SNG must, at a minimum, be equivalent to the quality required for interstate pipeline gas before a utility is required to accept and pay for SNG gas.

(14) Nothing in the sourcing agreement will require a utility to construct any facilities to accept delivery of SNG. Provided, however, if a utility is required by law or otherwise elects to connect the clean coal SNG brownfield facility to an interstate pipeline, then the utility shall be entitled to recover pursuant to its tariffs all just and reasonable costs that are prudently incurred. Any costs incurred by the utility to receive, deliver, manage, or otherwise accommodate purchases under the SNG sourcing agreement will be fully recoverable through a utility's purchased gas adjustment clause rider mechanism in conjunction with a SNG brownfield facility rider mechanism. The SNG brownfield facility rider mechanism (A) shall be applicable to all customers who receive transportation service from the utility, (B) shall be designed to have an equal percent impact on the transportation services rates of each class of the utility's customers, and (C) shall accurately reflect the net consumer savings, if any, and above-market costs, if any, associated with the utility receiving, delivering, managing, or otherwise accommodating purchases under the SNG sourcing agreement.

(15) Remedies for the clean coal SNG brownfield facility's failure to deliver a designated amount for a designated period.

(16) The clean coal SNG brownfield facility shall make a good faith effort to ensure that an amount equal to not less than 15% of the value of its prime construction contract for the facility shall be established as a goal to be awarded to minority owned businesses, female owned businesses, and businesses owned by a person with a disability; provided that at least 75% of the amount of such total goal shall be for minority owned businesses. "Minority owned business", "female owned business", and "business owned by a person with a disability" shall have the meanings ascribed to them in Section 2 of the Business Enterprise for Minorities, Females and Persons with Disabilities Act.

(17) Prior to the clean coal SNG brownfield facility issuing a notice to proceed to construction, the clean coal SNG brownfield facility shall file with the Commission a certificate from an independent engineer that the clean coal SNG brownfield facility has (A) obtained all applicable State and federal environmental permits required for construction; (B) obtained approval from the Commission of a carbon capture and sequestration plan; and (C) obtained all necessary permits required for construction for the transportation and sequestration of carbon dioxide as set forth in the Commission-approved carbon capture and sequestration plan.

(h-2) Consumer protection reserve account. The clean coal SNG brownfield facility shall guarantee a minimum of $100,000,000 in consumer savings to customers of the utilities that have entered into sourcing agreements with the clean coal SNG brownfield facility, calculated in real 2010 dollars at the conclusion of the term of the sourcing agreement by comparing the delivered SNG price to the Chicago City-gate price on a weighted daily basis for each day over the entire term of the sourcing agreement. Prior to the clean coal SNG brownfield facility issuing a notice to proceed to construction, the clean coal SNG brownfield facility shall establish a consumer protection reserve account for the benefit of the retail customers of the utilities that have entered into sourcing agreements with the clean coal SNG brownfield facility pursuant to subsection (h-1), with cash principal in the amount of $150,000,000. Such cash principal shall only be recovered through the consumer protection reserve account and not as a cost to be recovered in the delivered SNG price pursuant to subsection (h-3) of this Section. The consumer protection reserve account shall be maintained and administered by an independent trustee that is mutually agreed upon by the clean coal SNG brownfield facility, the utilities, and the Commission in an interest-bearing account in accordance with the following:

(1) The clean coal SNG brownfield facility monthly shall calculate (A) the difference between the monthly delivered SNG price and the Chicago City-gate price, by comparing the delivered SNG price, which shall include the cost of transportation to the delivery point, if any, to the Chicago City-gate price on a weighted daily basis for each day of the prior month based upon a mutually agreed upon published index and (B) the overage amount, if any, by calculating the annualized incremental additional cost, if any, of the delivered SNG in excess of 2.015% of the average annual inflation-adjusted amounts paid by all gas distribution customers in connection with natural gas service during the 5 years ending May 31, 2010.

(2) During the first 2 years of operation of the facility:

(A) to the extent there is an overage amount, the consumer protection reserve account shall be used to provide a credit to reduce the SNG price by an amount equal to the overage amount; and

(B) to the extent the monthly delivered SNG price is less than or equal to the Chicago City-gate price, the utility shall credit the difference between the monthly delivered SNG price and the monthly Chicago City-gate price, if any, to the consumer protection reserve account. Such credit issued pursuant to this paragraph (B) shall be deemed prudent and reasonable and not subject to a Commission prudence review;

(3) After 2 years of operation of the facility, and monthly, on an on-going basis, thereafter:

(A) to the extent that the monthly delivered SNG price is less than or equal to the Chicago City-gate price, calculated using the weighted average of the daily Chicago City-gate price on a daily basis over the entire month, the utility shall credit the difference, if any, to the consumer protection reserve account. Such credit issued pursuant to this subparagraph (A) shall be deemed prudent and reasonable and not subject to a Commission prudence review;

(B) any amounts in the consumer protection reserve account in excess of the consumer protection reserve account principal maximum amount shall be distributed as follows: (i) if retail customers have not realized net consumer savings, calculated by comparing the delivered SNG price to the weighted average of the daily Chicago City-gate price on a daily basis over the entire term of the sourcing agreement to date, then 50% of any amounts in the consumer protection reserve account in excess of the consumer protection reserve account principal maximum shall be distributed to the clean coal SNG brownfield facility, with the remaining 50% of any such additional amounts being credited to retail customers, and (ii) if retail customers have realized net consumer savings, then 100% of any amounts in the consumer protection reserve account in excess of the consumer protection reserve account principal maximum shall be distributed to the clean coal SNG brownfield facility; provided, however, that under no circumstances shall the total cumulative amount distributed to the clean coal SNG brownfield facility under this subparagraph (B) exceed $150,000,000;

(C) to the extent there is an overage amount, after distributing the amounts pursuant to subparagraph (B) of this paragraph (3), if any, the consumer protection reserve account shall be used to provide a credit to reduce the SNG price by an amount equal to the overage amount;

(D) if retail customers have realized net consumer savings, calculated by comparing the delivered SNG price to the weighted average of the daily Chicago City-gate price on a daily basis over the entire term of the sourcing agreement to date, then after distributing the amounts pursuant to subparagraphs (B) and (C) of this paragraph (3), 50% of any additional amounts in the consumer protection reserve account in excess of the consumer protection reserve account principal maximum shall be distributed to the clean coal SNG brownfield facility, with the remaining 50% of any such additional amounts being credited to retail customers; provided, however, that if retail customers have not realized such net consumer savings, no such distribution shall be made to the clean coal SNG brownfield facility, and 100% of such additional amounts shall be credited to the retail customers to the extent the consumer protection reserve account exceeds the consumer protection reserve account principal maximum amount.

(4) Fifty percent of all additional net revenue, defined as miscellaneous net revenue after cost allowance for costs associated with additional net revenue that are not otherwise recoverable pursuant to subsection (h-3) of this Section, including net revenue from sales of substitute natural gas derived from the facility above the nameplate capacity of the facility and other by-products produced by the facility, shall be credited to the consumer protection reserve account.

(5) At the conclusion of the term of the sourcing agreement, to the extent retail customers have not saved the minimum of $100,000,000 in consumer savings as guaranteed in this subsection (h-2), amounts in the consumer protection reserve account shall be credited to retail customers to the extent the retail customers have saved the minimum of $100,000,000; 50% of any additional amounts in the consumer protection reserve account shall be distributed to the company, and the remaining 50% shall be distributed to retail customers.

(6) If, at the conclusion of the term of the sourcing agreement, the customers have not saved the minimum $100,000,000 in savings as guaranteed in this subsection (h-2) and the consumer protection reserve account has been depleted, then the clean coal SNG brownfield facility shall be liable for any remaining amount owed to the retail customers to the extent that the customers are provided with the $100,000,000 in savings as guaranteed in this subsection (h-2). The retail customers shall have first priority in recovering that debt above any creditors, except the original senior secured lender to the extent that the original senior secured lender has any senior secured debt outstanding, including any clean coal SNG brownfield facility parent companies or affiliates.

(7) The clean coal SNG brownfield facility, the utilities, and the trustee shall work together to take commercially reasonable steps to minimize the tax impact of these transactions, while preserving the consumer benefits.

(8) The clean coal SNG brownfield facility shall each month, starting in the facility's first year of commercial operation, file with the Commission, in such form as the Commission shall require, a report as to the consumer protection reserve account. The monthly report must contain the following information:

(A) the extent the monthly delivered SNG price is greater than, less than, or equal to the Chicago City-gate price;

(B) the amount credited or debited to the consumer protection reserve account during the month;

(C) the amounts credited to consumers and distributed to the clean coal SNG brownfield facility during the month;

(D) the total amount of the consumer protection reserve account at the beginning and end of the month;

(E) the total amount of consumer savings to date;

(F) a confidential summary of the inputs used to calculate the additional net revenue; and

(G) any other additional information the Commission shall require.

When any report is erroneous or defective or appears to the Commission to be erroneous or defective, the Commission may notify the clean coal SNG brownfield facility to amend the report within 30 days, and, before or after the termination of the 30-day period, the Commission may examine the trustee of the consumer protection reserve account or the officers, agents, employees, books, records, or accounts of the clean coal SNG brownfield facility and correct such items in the report as upon such examination the Commission may find defective or erroneous. All reports shall be under oath.

All reports made to the Commission by the clean coal SNG brownfield facility and the contents of the reports shall be open to public inspection and shall be deemed a public record under the Freedom of Information Act. Such reports shall be preserved in the office of the Commission. The Commission shall publish an annual summary of the reports prior to February 1 of the following year. The annual summary shall be made available to the public on the Commission's website and shall be submitted to the General Assembly.

Any facility that fails to file a report required under this paragraph (8) to the Commission within the time specified or to make specific answer to any question propounded by the Commission within 30 days from the time it is lawfully required to do so, or within such further time not to exceed 90 days as may in its discretion be allowed by the Commission, shall pay a penalty of $500 to the Commission for each day it is in default.

Any person who willfully makes any false report to the Commission or to any member, officer, or employee thereof, any person who willfully in a report withholds or fails to provide material information to which the Commission is entitled under this paragraph (8) and which information is either required to be filed by statute, rule, regulation, order, or decision of the Commission or has been requested by the Commission, and any person who willfully aids or abets such person shall be guilty of a Class A misdemeanor.

(h-3) Recoverable costs and revenue by the clean coal SNG brownfield facility.

(1) A capital recovery charge approved by the Commission shall be recoverable by the clean coal SNG brownfield facility under a sourcing agreement. The capital recovery charge shall be comprised of capital costs and a reasonable rate of return. "Capital costs" means costs to be incurred in connection with the construction and development of a facility, as defined in Section 1-10 of the Illinois Power Agency Act, and such other costs as the Capital Development Board deems appropriate to be recovered in the capital recovery charge.

(A) Capital costs. The Capital Development Board shall calculate a range of capital costs that it believes would be reasonable for the clean coal SNG brownfield facility to recover under the sourcing agreement. In making this determination, the Capital Development Board shall review the facility cost report, if any, of the clean coal SNG brownfield facility, adjusting the results based on the change in the Annual Consumer Price Index for All Urban Consumers for the Midwest Region as published in April by the United States Department of Labor, Bureau of Labor Statistics, the final draft of the sourcing agreement, and the rate of return approved by the Commission. In addition, the Capital Development Board may consult as much as it deems necessary with the clean coal SNG brownfield facility and conduct whatever research and investigation it deems necessary.

The Capital Development Board shall retain an engineering expert to assist in determining both the range of capital costs and the range of operations and maintenance costs that it believes would be reasonable for the clean coal SNG brownfield facility to recover under the sourcing agreement. Provided, however, that such expert shall: (i) not have been involved in the clean coal SNG brownfield facility's facility cost report, if any, (ii) not own or control any direct or indirect interest in the initial clean coal facility, and (iii) have no contractual relationship with the clean coal SNG brownfield facility. In order to qualify as an independent expert, a person or company must have:

(i) direct previous experience conducting front-end engineering and design studies for large-scale energy facilities and administering large-scale energy operations and maintenance contracts, which may be particularized to the specific type of financing associated with the clean coal SNG brownfield facility;

(ii) an advanced degree in economics, mathematics, engineering, or a related area of study;

(iii) ten years of experience in the energy sector, including construction and risk management experience;

(iv) expertise in assisting companies with obtaining financing for large-scale energy projects, which may be particularized to the specific type of financing associated with the clean coal SNG brownfield facility;

(v) expertise in operations and maintenance which may be particularized to the specific type of operations and maintenance associated with the clean coal SNG brownfield facility;

(vi) expertise in credit and contract protocols;

(vii) adequate resources to perform and fulfill the required functions and responsibilities; and

(viii) the absence of a conflict of interest and inappropriate bias for or against an affected gas utility or the clean coal SNG brownfield facility.

The clean coal SNG brownfield facility and the Illinois Power Agency shall cooperate with the Capital Development Board in any investigation it deems necessary. The Capital Development Board shall make its final determination of the range of capital costs confidentially and shall submit that range to the Commission in a confidential filing within 120 days after July 13, 2011 (the effective date of Public Act 97-096). The clean coal SNG brownfield facility shall submit to the Commission its estimate of the capital costs to be recovered under the sourcing agreement. Only after the clean coal SNG brownfield facility has submitted this estimate shall the Commission publicly announce the range of capital costs submitted by the Capital Development Board.

In the event that the estimate submitted by the clean coal SNG brownfield facility is within or below the range submitted by the Capital Development Board, the clean coal SNG brownfield facility's estimate shall be approved by the Commission as the amount of capital costs to be recovered under the sourcing agreement. In the event that the estimate submitted by the clean coal SNG brownfield facility is above the range submitted by the Capital Development Board, the amount of capital costs at the lowest end of the range submitted by the Capital Development Board shall be approved by the Commission as the amount of capital costs to be recovered under the sourcing agreement. Within 15 days after the Capital Development Board has submitted its range and the clean coal SNG brownfield facility has submitted its estimate, the Commission shall approve the capital costs for the clean coal SNG brownfield facility.

The Capital Development Board shall monitor the construction of the clean coal SNG brownfield facility for the full duration of construction to assess potential cost overruns. The Capital Development Board, in its discretion, may retain an expert to facilitate such monitoring. The clean coal SNG brownfield facility shall pay a reasonable fee as required by the Capital Development Board for the Capital Development Board's services under this subsection (h-3) to be deposited into the Capital Development Board Revolving Fund, and such fee shall not be passed through to a utility or its customers. If an expert is retained by the Capital Development Board for monitoring of construction, then the clean coal SNG brownfield facility must pay for the expert's reasonable fees and such costs shall not be passed through to a utility or its customers.

(B) Rate of Return. No later than 30 days after the date on which the Illinois Power Agency submits a final draft sourcing agreement, the Commission shall hold a public hearing to determine the rate of return to be recovered under the sourcing agreement. Rate of return shall be comprised of the clean coal SNG brownfield facility's actual cost of debt, including mortgage-style amortization, and a reasonable return on equity. The Commission shall post notice of the hearing on its website no later than 10 days prior to the date of the hearing. The Commission shall provide the public and all interested parties, including the gas utilities, the Attorney General, and the Illinois Power Agency, an opportunity to be heard.

In determining the return on equity, the Commission shall select a commercially reasonable return on equity taking into account the return on equity being received by developers of similar facilities in or outside of Illinois, the need to balance an incentive for clean-coal technology with the need to protect ratepayers from high gas prices, the risks being borne by the clean coal SNG brownfield facility in the final draft sourcing agreement, and any other information that the Commission may deem relevant. The Commission may establish a return on equity that varies with the amount of savings, if any, to customers during the term of the sourcing agreement, comparing the delivered SNG price to a daily weighted average price of natural gas, based upon an index. The Illinois Power Agency shall recommend a return on equity to the Commission using the same criteria. Within 60 days after receiving the final draft sourcing agreement from the Illinois Power Agency, the Commission shall approve the rate of return for the clean coal brownfield facility. Within 30 days after obtaining debt financing for the clean coal SNG brownfield facility, the clean coal SNG brownfield facility shall file a notice with the Commission identifying the actual cost of debt.

(2) Operations and maintenance costs approved by the Commission shall be recoverable by the clean coal SNG brownfield facility under the sourcing agreement. The operations and maintenance costs mean costs that have been incurred for the administration, supervision, operation, maintenance, preservation, and protection of the clean coal SNG brownfield facility's physical plant.

The Capital Development Board shall calculate a range of operations and maintenance costs that it believes would be reasonable for the clean coal SNG brownfield facility to recover under the sourcing agreement, incorporating an inflation index or combination of inflation indices to most accurately reflect the actual costs of operating the clean coal SNG brownfield facility. In making this determination, the Capital Development Board shall review the facility cost report, if any, of the clean coal SNG brownfield facility, adjusting the results for inflation based on the change in the Annual Consumer Price Index for All Urban Consumers for the Midwest Region as published in April by the United States Department of Labor, Bureau of Labor Statistics, the final draft of the sourcing agreement, and the rate of return approved by the Commission. In addition, the Capital Development Board may consult as much as it deems necessary with the clean coal SNG brownfield facility and conduct whatever research and investigation it deems necessary. As set forth in subparagraph (A) of paragraph (1) of this subsection (h-3), the Capital Development Board shall retain an independent engineering expert to assist in determining both the range of operations and maintenance costs that it believes would be reasonable for the clean coal SNG brownfield facility to recover under the sourcing agreement. The clean coal SNG brownfield facility and the Illinois Power Agency shall cooperate with the Capital Development Board in any investigation it deems necessary. The Capital Development Board shall make its final determination of the range of operations and maintenance costs confidentially and shall submit that range to the Commission in a confidential filing within 120 days after July 13, 2011.

The clean coal SNG brownfield facility shall submit to the Commission its estimate of the operations and maintenance costs to be recovered under the sourcing agreement. Only after the clean coal SNG brownfield facility has submitted this estimate shall the Commission publicly announce the range of operations and maintenance costs submitted by the Capital Development Board. In the event that the estimate submitted by the clean coal SNG brownfield facility is within or below the range submitted by the Capital Development Board, the clean coal SNG brownfield facility's estimate shall be approved by the Commission as the amount of operations and maintenance costs to be recovered under the sourcing agreement. In the event that the estimate submitted by the clean coal SNG brownfield facility is above the range submitted by the Capital Development Board, the amount of operations and maintenance costs at the lowest end of the range submitted by the Capital Development Board shall be approved by the Commission as the amount of operations and maintenance costs to be recovered under the sourcing agreement. Within 15 days after the Capital Development Board has submitted its range and the clean coal SNG brownfield facility has submitted its estimate, the Commission shall approve the operations and maintenance costs for the clean coal SNG brownfield facility.

The clean coal SNG brownfield facility shall pay for the independent engineering expert's reasonable fees and such costs shall not be passed through to a utility or its customers. The clean coal SNG brownfield facility shall pay a reasonable fee as required by the Capital Development Board for the Capital Development Board's services under this subsection (h-3) to be deposited into the Capital Development Board Revolving Fund, and such fee shall not be passed through to a utility or its customers.

(3) Sequestration costs approved by the Commission shall be recoverable by the clean coal SNG brownfield facility. "Sequestration costs" means costs to be incurred by the clean coal SNG brownfield facility in accordance with its Commission-approved carbon capture and sequestration plan to:

(A) capture carbon dioxide;

(B) build, operate, and maintain a sequestration site in which carbon dioxide may be injected;

(C) build, operate, and maintain a carbon dioxide pipeline; and

(D) transport the carbon dioxide to the sequestration site or a pipeline.

The Commission shall assess the prudency of the sequestration costs for the clean coal SNG brownfield facility before construction commences at the sequestration site or pipeline. Any revenues the clean coal SNG brownfield facility receives as a result of the capture, transportation, or sequestration of carbon dioxide shall be first credited against all sequestration costs, with the positive balance, if any, treated as additional net revenue.

The Commission may, in its discretion, retain an expert to assist in its review of sequestration costs. The clean coal SNG brownfield facility shall pay for the expert's reasonable fees if an expert is retained by the Commission, and such costs shall not be passed through to a utility or its customers. Once made, the Commission's determination of the amount of recoverable sequestration costs shall not be increased unless the clean coal SNG brownfield facility can show by clear and convincing evidence that (i) the costs were not reasonably foreseeable; (ii) the costs were due to circumstances beyond the clean coal SNG brownfield facility's control; and (iii) the clean coal SNG brownfield facility took all reasonable steps to mitigate the costs. If the Commission determines that sequestration costs may be increased, the Commission shall provide for notice and a public hearing for approval of the increased sequestration costs.

(4) Actual delivered and processed fuel costs shall be set by the Illinois Power Agency through a SNG feedstock procurement, pursuant to Sections 1-20, 1-77, and 1-78 of the Illinois Power Agency Act, to be performed at least every 5 years and purchased by the clean coal SNG brownfield facility pursuant to feedstock procurement contracts developed by the Illinois Power Agency, with coal comprising at least 50% of the total feedstock over the term of the sourcing agreement and petroleum coke comprising the remainder of the SNG feedstock. If the Commission fails to approve a feedstock procurement plan or fails to approve the results of a feedstock procurement event, then the fuel shall be purchased by the company month-by-month on the spot market and those actual delivered and processed fuel costs shall be recoverable under the sourcing agreement. If a supplier defaults under the terms of a procurement contract, then the Illinois Power Agency shall immediately initiate a feedstock procurement process to obtain a replacement supply, and, prior to the conclusion of that process, fuel shall be purchased by the company month-by-month on the spot market and those actual delivered and processed fuel costs shall be recoverable under the sourcing agreement.

(5) Taxes and fees imposed by the federal government, the State, or any unit of local government applicable to the clean coal SNG brownfield facility, excluding income tax, shall be recoverable by the clean coal SNG brownfield facility under the sourcing agreement to the extent such taxes and fees were not applicable to the facility on July 13, 2011.

(6) The actual transportation costs, in accordance with the applicable utility's tariffs, and third-party marketer costs incurred by the company, if any, associated with transporting the SNG from the clean coal SNG brownfield facility to the Chicago City-gate to sell such SNG into the natural gas markets shall be recoverable under the sourcing agreement.

(7) Unless otherwise provided, within 30 days after a decision of the Commission on recoverable costs under this Section, any interested party to the Commission's decision may apply for a rehearing with respect to the decision. The Commission shall receive and consider the application for rehearing and shall grant or deny the application in whole or in part within 20 days after the date of the receipt of the application by the Commission. If no rehearing is applied for within the required 30 days or an application for rehearing is denied, then the Commission decision shall be final. If an application for rehearing is granted, then the Commission shall hold a rehearing within 30 days after granting the application. The decision of the Commission upon rehearing shall be final.

Any person affected by a decision of the Commission under this subsection (h-3) may have the decision reviewed only under and in accordance with the Administrative Review Law. Unless otherwise provided, the provisions of the Administrative Review Law, all amendments and modifications to that Law, and the rules adopted pursuant to that Law shall apply to and govern all proceedings for the judicial review of final administrative decisions of the Commission under this subsection (h-3). The term "administrative decision" is defined as in Section 3-101 of the Code of Civil Procedure.

(8) The Capital Development Board shall adopt and make public a policy detailing the process for retaining experts under this Section. Any experts retained to assist with calculating the range of capital costs or operations and maintenance costs shall be retained no later than 45 days after July 13, 2011.

(h-4) No later than 90 days after the Illinois Power Agency submits the final draft sourcing agreement pursuant to subsection (h-1), the Commission shall approve a sourcing agreement containing (i) the capital costs, rate of return, and operations and maintenance costs established pursuant to subsection (h-3) and (ii) all other terms and conditions, rights, provisions, exceptions, and limitations contained in the final draft sourcing agreement; provided, however, the Commission shall correct typographical and scrivener's errors and modify the contract only as necessary to provide that the gas utility does not have the right to terminate the sourcing agreement due to any future events that may occur other than the clean coal SNG brownfield facility's failure to timely meet milestones, uncured default, extended force majeure, or abandonment. Once the sourcing agreement is approved, then the gas utility subject to that sourcing agreement shall have 45 days after the date of the Commission's approval to enter into the sourcing agreement.

(h-5) Sequestration enforcement.

(A) All contracts entered into under subsection (h) of this Section and all sourcing agreements under subsection (h-1) of this Section, regardless of duration, shall require the owner of any facility supplying SNG under the contract or sourcing agreement to provide certified documentation to the Commission each year, starting in the facility's first year of commercial operation, accurately reporting the quantity of carbon dioxide emissions from the facility that have been captured and sequestered and reporting any quantities of carbon dioxide released from the site or sites at which carbon dioxide emissions were sequestered in prior years, based on continuous monitoring of those sites.

(B) If, in any year, the owner of the clean coal SNG facility fails to demonstrate that the SNG facility captured and sequestered at least 90% of the total carbon dioxide emissions that the facility would otherwise emit or that sequestration of emissions from prior years has failed, resulting in the release of carbon dioxide into the atmosphere, then the owner of the clean coal SNG facility must pay a penalty of $20 per ton of excess carbon dioxide emissions not to exceed $40,000,000, in any given year which shall be deposited into the Energy Efficiency Trust Fund and distributed pursuant to subsection (b) of Section 6-6 of the Renewable Energy, Energy Efficiency, and Coal Resources Development Law of 1997. On or before the 5-year anniversary of the execution of the contract and every 5 years thereafter, an expert hired by the owner of the facility with the approval of the Attorney General shall conduct an analysis to determine the cost of sequestration of at least 90% of the total carbon dioxide emissions the plant would otherwise emit. If the analysis shows that the actual annual cost is greater than the penalty, then the penalty shall be increased to equal the actual cost. Provided, however, to the extent that the owner of the facility described in subsection (h) of this Section can demonstrate that the failure was as a result of acts of God (including fire, flood, earthquake, tornado, lightning, hurricane, or other natural disaster); any amendment, modification, or abrogation of any applicable law or regulation that would prevent performance; war; invasion; act of foreign enemies; hostilities (regardless of whether war is declared); civil war; rebellion; revolution; insurrection; military or usurped power or confiscation; terrorist activities; civil disturbance; riots; nationalization; sabotage; blockage; or embargo, the owner of the facility described in subsection (h) of this Section shall not be subject to a penalty if and only if (i) it promptly provides notice of its failure to the Commission; (ii) as soon as practicable and consistent with any order or direction from the Commission, it submits to the Commission proposed modifications to its carbon capture and sequestration plan; and (iii) it carries out its proposed modifications in the manner and time directed by the Commission.

If the Commission finds that the facility has not satisfied each of these requirements, then the facility shall be subject to the penalty. If the owner of the clean coal SNG facility captured and sequestered more than 90% of the total carbon dioxide emissions that the facility would otherwise emit, then the owner of the facility may credit such additional amounts to reduce the amount of any future penalty to be paid. The penalty resulting from the failure to capture and sequester at least the minimum amount of carbon dioxide shall not be passed on to a utility or its customers.

If the clean coal SNG facility fails to meet the requirements specified in this subsection (h-5), then the Attorney General, on behalf of the People of the State of Illinois, shall bring an action to enforce the obligations related to the facility set forth in this subsection (h-5), including any penalty payments owed, but not including the physical obligation to capture and sequester at least 90% of the total carbon dioxide emissions that the facility would otherwise emit. Such action may be filed in any circuit court in Illinois. By entering into a contract pursuant to subsection (h) of this Section, the clean coal SNG facility agrees to waive any objections to venue or to the jurisdiction of the court with regard to the Attorney General's action under this subsection (h-5).

Compliance with the sequestration requirements and any penalty requirements specified in this subsection (h-5) for the clean coal SNG facility shall be assessed annually by the Commission, which may in its discretion retain an expert to facilitate its assessment. If any expert is retained by the Commission, then the clean coal SNG facility shall pay for the expert's reasonable fees, and such costs shall not be passed through to the utility or its customers. A SNG facility operating pursuant to this subsection (h-5) shall not forfeit its designation as a clean coal SNG facility or a clean coal SNG brownfield facility if the facility fails to fully comply with the applicable carbon sequestration sequestrian requirements in any given year, provided the requisite offsets are purchased or requisite penalties are paid.

In addition, carbon dioxide emission credits received by the clean coal SNG facility in connection with sequestration of carbon dioxide from the facility must be sold in a timely fashion with any revenue, less applicable fees and expenses and any expenses required to be paid by facility for carbon dioxide transportation or sequestration, deposited into the reconciliation account within 30 days after receipt of such funds by the owner of the clean coal SNG facility.

The clean coal SNG facility is prohibited from transporting or sequestering carbon dioxide unless the owner of the carbon dioxide pipeline that transfers the carbon dioxide from the facility and the owner of the sequestration site where the carbon dioxide captured by the facility is stored has acquired all applicable permits under applicable State and federal laws, statutes, rules, or regulations prior to the transfer or sequestration of carbon dioxide. The responsibility for compliance with the sequestration requirements specified in this subsection (h-5) for the clean coal SNG facility shall reside solely with the clean coal SNG facility, regardless of whether the facility has contracted with another party to capture, transport, or sequester carbon dioxide.

(C) If, in any year, the owner of a clean coal SNG brownfield facility fails to demonstrate that the clean coal SNG brownfield facility captured and sequestered at least 85% of the total carbon dioxide emissions that the facility would otherwise emit, then the owner of the clean coal SNG brownfield facility must pay a penalty of $20 per ton of excess carbon emissions up to $20,000,000, which shall be deposited into the Energy Efficiency Trust Fund and distributed pursuant to subsection (b) of Section 6-6 of the Renewable Energy, Energy Efficiency, and Coal Resources Development Law of 1997. Provided, however, to the extent that the owner of the clean coal SNG brownfield facility can demonstrate that the failure was as a result of acts of God (including fire, flood, earthquake, tornado, lightning, hurricane, or other natural disaster); any amendment, modification, or abrogation of any applicable law or regulation that would prevent performance; war; invasion; act of foreign enemies; hostilities (regardless of whether war is declared); civil war; rebellion; revolution; insurrection; military or usurped power or confiscation; terrorist activities; civil disturbances; riots; nationalization; sabotage; blockage; or embargo, the owner of the clean coal SNG brownfield facility shall not be subject to a penalty if and only if (i) it promptly provides notice of its failure to the Commission; (ii) as soon as practicable and consistent with any order or direction from the Commission, it submits to the Commission proposed modifications to its carbon capture and sequestration plan; and (iii) it carries out its proposed modifications in the manner and time directed by the Commission. If the Commission finds that the facility has not satisfied each of these requirements, then the facility shall be subject to the penalty. If the owner of a clean coal SNG brownfield facility demonstrates that the clean coal SNG brownfield facility captured and sequestered more than 85% of the total carbon emissions that the facility would otherwise emit, the owner of the clean coal SNG brownfield facility may credit such additional amounts to reduce the amount of any future penalty to be paid. The penalty resulting from the failure to capture and sequester at least the minimum amount of carbon dioxide shall not be passed on to a utility or its customers.

In addition to any penalty for the clean coal SNG brownfield facility's failure to capture and sequester at least its minimum sequestration requirement, the Attorney General, on behalf of the People of the State of Illinois, shall bring an action for specific performance of this subsection (h-5). Such action may be filed in any circuit court in Illinois. By entering into a sourcing agreement pursuant to subsection (h-1) of this Section, the clean coal SNG brownfield facility agrees to waive any objections to venue or to the jurisdiction of the court with regard to the Attorney General's action for specific performance under this subsection (h-5).

Compliance with the sequestration requirements and penalty requirements specified in this subsection (h-5) for the clean coal SNG brownfield facility shall be assessed annually by the Commission, which may in its discretion retain an expert to facilitate its assessment. If an expert is retained by the Commission, then the clean coal SNG brownfield facility shall pay for the expert's reasonable fees, and such costs shall not be passed through to a utility or its customers.

Responsibility for compliance with the sequestration requirements specified in this subsection (h-5) for the clean coal SNG brownfield facility shall reside solely with the clean coal SNG brownfield facility regardless of whether the facility has contracted with another party to capture, transport, or sequester carbon dioxide.

(h-7) Sequestration permitting, oversight, and investigations.

(1) No clean coal facility or clean coal SNG brownfield facility may transport or sequester carbon dioxide unless the Commission approves the method of carbon dioxide transportation or sequestration. Such approval shall be required regardless of whether the facility has contracted with another to transport or sequester the carbon dioxide. Nothing in this subsection (h-7) shall release the owner or operator of a carbon dioxide sequestration site or carbon dioxide pipeline from any other permitting requirements under applicable State and federal laws, statutes, rules, or regulations.

(2) The Commission shall review carbon dioxide transportation and sequestration methods proposed by a clean coal facility or a clean coal SNG brownfield facility and shall approve those methods it deems reasonable and cost-effective. For purposes of this review, "cost-effective" means a commercially reasonable price for similar carbon dioxide transportation or sequestration techniques. In determining whether sequestration is reasonable and cost-effective, the Commission may consult with the Illinois State Geological Survey and retain third parties to assist in its determination, provided that such third parties shall not own or control any direct or indirect interest in the facility that is proposing the carbon dioxide transportation or the carbon dioxide sequestration method and shall have no contractual relationship with that facility. If a third party is retained by the Commission, then the facility proposing the carbon dioxide transportation or sequestration method shall pay for the expert's reasonable fees, and these costs shall not be passed through to a utility or its customers.

No later than 6 months prior to the date upon which the owner intends to commence construction of a clean coal facility or the clean coal SNG brownfield facility, the owner of the facility shall file with the Commission a carbon dioxide transportation or sequestration plan. The Commission shall hold a public hearing within 30 days after receipt of the facility's carbon dioxide transportation or sequestration plan. The Commission shall post notice of the review on its website upon submission of a carbon dioxide transportation or sequestration method and shall accept written public comments. The Commission shall take the comments into account when making its decision.

The Commission may not approve a carbon dioxide sequestration method if the owner or operator of the sequestration site has not received (i) an Underground Injection Control permit from the United States Environmental Protection Agency, or from the Illinois Environmental Protection Agency pursuant to the Environmental Protection Act; (ii) an Underground Injection Control permit from the Illinois Department of Natural Resources pursuant to the Illinois Oil and Gas Act; or (iii) an Underground Injection Control permit from the United States Environmental Protection Agency or a permit similar to items (i) or (ii) from the state in which the sequestration site is located if the sequestration will take place outside of Illinois. The Commission shall approve or deny the carbon dioxide transportation or sequestration method within 90 days after the receipt of all required information.

(3) At least annually, the Illinois Environmental Protection Agency shall inspect all carbon dioxide sequestration sites in Illinois. The Illinois Environmental Protection Agency may, as often as deemed necessary, monitor and conduct investigations of those sites. The owner or operator of the sequestration site must cooperate with the Illinois Environmental Protection Agency investigations of carbon dioxide sequestration sites.

If the Illinois Environmental Protection Agency determines at any time a site creates conditions that warrant the issuance of a seal order under Section 34 of the Environmental Protection Act, then the Illinois Environmental Protection Agency shall seal the site pursuant to the Environmental Protection Act. If the Illinois Environmental Protection Agency determines at any time a carbon dioxide sequestration site creates conditions that warrant the institution of a civil action for an injunction under Section 43 of the Environmental Protection Act, then the Illinois Environmental Protection Agency shall request the State's Attorney or the Attorney General institute such action. The Illinois Environmental Protection Agency shall provide notice of any such actions as soon as possible on its website. The SNG facility shall incur all reasonable costs associated with any such inspection or monitoring of the sequestration sites, and these costs shall not be recoverable from utilities or their customers.

(4) (Blank).

(h-9) The clean coal SNG brownfield facility shall have the right to recover prudently incurred increased costs or reduced revenue resulting from any new or amendatory legislation or other action. The State of Illinois pledges that the State will not enact any law or take any action to:

(1) break, or repeal the authority for, sourcing agreements approved by the Commission and entered into between public utilities and the clean coal SNG brownfield facility;

(2) deny public utilities full cost recovery for their costs incurred under those sourcing agreements; or

(3) deny the clean coal SNG brownfield facility full cost and revenue recovery as provided under those sourcing agreements that are recoverable pursuant to subsection (h-3) of this Section.

These pledges are for the benefit of the parties to those sourcing agreements and the issuers and holders of bonds or other obligations issued or incurred to finance or refinance the clean coal SNG brownfield facility. The clean coal SNG brownfield facility is authorized to include and refer to these pledges in any financing agreement into which it may enter in regard to those sourcing agreements.

The State of Illinois retains and reserves all other rights to enact new or amendatory legislation or take any other action, without impairment of the right of the clean coal SNG brownfield facility to recover prudently incurred increased costs or reduced revenue resulting from the new or amendatory legislation or other action, including, but not limited to, such legislation or other action that would (i) directly or indirectly raise the costs the clean coal SNG brownfield facility must incur; (ii) directly or indirectly place additional restrictions, regulations, or requirements on the clean coal SNG brownfield facility; (iii) prohibit sequestration in general or prohibit a specific sequestration method or project; or (iv) increase minimum sequestration requirements for the clean coal SNG brownfield facility to the extent technically feasible. The clean coal SNG brownfield facility shall have the right to recover prudently incurred increased costs or reduced revenue resulting from the new or amendatory legislation or other action as described in this subsection (h-9).

(h-10) Contract costs for SNG incurred by an Illinois gas utility are reasonable and prudent and recoverable through the purchased gas adjustment clause and are not subject to review or disallowance by the Commission. Contract costs are costs incurred by the utility under the terms of a contract that incorporates the terms stated in subsection (h) of this Section as confirmed in writing by the Illinois Power Agency as set forth in subsection (h) of this Section, which confirmation shall be deemed conclusive, or as a consequence of or condition to its performance under the contract, including (i) amounts paid for SNG under the SNG contract and (ii) costs of transportation and storage services of SNG purchased from interstate pipelines under federally approved tariffs. The Illinois gas utility shall initiate a clean coal SNG facility rider mechanism that (A) shall be applicable to all customers who receive transportation service from the utility, (B) shall be designed to have an equal percentage impact on the transportation services rates of each class of the utility's total customers, and (C) shall accurately reflect the net customer savings, if any, and above market costs, if any, under the SNG contract. Any contract, the terms of which have been confirmed in writing by the Illinois Power Agency as set forth in subsection (h) of this Section and the performance of the parties under such contract cannot be grounds for challenging prudence or cost recovery by the utility through the purchased gas adjustment clause, and in such cases, the Commission is directed not to consider, and has no authority to consider, any attempted challenges.

The contracts entered into by Illinois gas utilities pursuant to subsection (h) of this Section shall provide that the utility retains the right to terminate the contract without further obligation or liability to any party if the contract has been impaired as a result of any legislative, administrative, judicial, or other governmental action that is taken that eliminates all or part of the prudence protection of this subsection (h-10) or denies the recoverability of all or part of the contract costs through the purchased gas adjustment clause. Should any Illinois gas utility exercise its right under this subsection (h-10) to terminate the contract, all contract costs incurred prior to termination are and will be deemed reasonable, prudent, and recoverable as and when incurred and not subject to review or disallowance by the Commission. Any order, issued by the State requiring or authorizing the discontinuation of the merchant function, defined as the purchase and sale of natural gas by an Illinois gas utility for the ultimate consumer in its service territory shall include provisions necessary to prevent the impairment of the value of any contract hereunder over its full term.

(h-11) All costs incurred by an Illinois gas utility in procuring SNG from a clean coal SNG brownfield facility pursuant to subsection (h-1) or a third-party marketer pursuant to subsection (h-1) are reasonable and prudent and recoverable through the purchased gas adjustment clause in conjunction with a SNG brownfield facility rider mechanism and are not subject to review or disallowance by the Commission; provided that if a utility is required by law or otherwise elects to connect the clean coal SNG brownfield facility to an interstate pipeline, then the utility shall be entitled to recover pursuant to its tariffs all just and reasonable costs that are prudently incurred. Sourcing agreement costs are costs incurred by the utility under the terms of a sourcing agreement that incorporates the terms stated in subsection (h-1) of this Section as approved by the Commission as set forth in subsection (h-4) of this Section, which approval shall be deemed conclusive, or as a consequence of or condition to its performance under the contract, including (i) amounts paid for SNG under the SNG contract and (ii) costs of transportation and storage services of SNG purchased from interstate pipelines under federally approved tariffs. Any sourcing agreement, the terms of which have been approved by the Commission as set forth in subsection (h-4) of this Section, and the performance of the parties under the sourcing agreement cannot be grounds for challenging prudence or cost recovery by the utility, and in these cases, the Commission is directed not to consider, and has no authority to consider, any attempted challenges.

(h-15) Reconciliation account. The clean coal SNG facility shall establish a reconciliation account for the benefit of the retail customers of the utilities that have entered into contracts with the clean coal SNG facility pursuant to subsection (h). The reconciliation account shall be maintained and administered by an independent trustee that is mutually agreed upon by the owners of the clean coal SNG facility, the utilities, and the Commission in an interest-bearing account in accordance with the following:

(1) The clean coal SNG facility shall conduct an analysis annually within 60 days after receiving the necessary cost information, which shall be provided by the gas utility within 6 months after the end of the preceding calendar year, to determine (i) the average annual contract SNG cost, which shall be calculated as the total amount paid for SNG purchased from the clean coal SNG facility over the preceding 12 months, plus the cost to the utility of the required transportation and storage services of SNG, divided by the total number of MMBtus of SNG actually purchased from the clean coal SNG facility in the preceding 12 months under the utility contract; (ii) the average annual natural gas purchase cost, which shall be calculated as the total annual supply costs paid for baseload natural gas (excluding any SNG) purchased by such utility over the preceding 12 months plus the costs of transportation and storage services of such natural gas (excluding such costs for SNG), divided by the total number of MMbtus of baseload natural gas (excluding SNG) actually purchased by the utility during the year; (iii) the cost differential, which shall be the difference between the average annual contract SNG cost and the average annual natural gas purchase cost; and (iv) the revenue share target which shall be the cost differential multiplied by the total amount of SNG purchased over the preceding 12 months under such utility contract.

(A) To the extent the annual average contract SNG cost is less than the annual average natural gas purchase cost, the utility shall credit an amount equal to the revenue share target to the reconciliation account. Such credit payment shall be made monthly starting within 30 days after the completed analysis in this subsection (h-15) and based on collections from all customers via a line item charge in all customer bills designed to have an equal percentage impact on the transportation services of each class of customers. Credit payments made pursuant to this subparagraph (A) shall be deemed prudent and reasonable and not subject to Commission prudence review.

(B) To the extent the annual average contract SNG cost is greater than the annual average natural gas purchase cost, the reconciliation account shall be used to provide a credit equal to the revenue share target to the utilities to be used to reduce the utility's natural gas costs through the purchased gas adjustment clause. Such payment shall be made within 30 days after the completed analysis pursuant to this subsection (h-15), but only to the extent that the reconciliation account has a positive balance.

(2) At the conclusion of the term of the SNG contracts pursuant to subsection (h) and the completion of the final annual analysis pursuant to this subsection (h-15), to the extent the facility owes any amount to retail customers, amounts in the account shall be credited to retail customers to the extent the owed amount is repaid; 50% of any additional amount in the reconciliation account shall be distributed to the utilities to be used to reduce the utilities' natural gas costs through the purchase gas adjustment clause with the remaining amount distributed to the clean coal SNG facility. Such payment shall be made within 30 days after the last completed analysis pursuant to this subsection (h-15). If the facility has repaid all owed amounts, if any, to retail customers and has distributed 50% of any additional amount in the account to the utilities, then the owners of the clean coal SNG facility shall have no further obligation to the utility or the retail customers.

If, at the conclusion of the term of the contracts pursuant to subsection (h) and the completion of the final annual analysis pursuant to this subsection (h-15), the facility owes any amount to retail customers and the account has been depleted, then the clean coal SNG facility shall be liable for any remaining amount owed to the retail customers. The clean coal SNG facility shall market the daily production of SNG and distribute on a monthly basis 5% of the amounts collected with respect to such future sales to the utilities in proportion to each utility's SNG contract to be used to reduce the utility's natural gas costs through the purchase gas adjustment clause; such payments to the utility shall continue until either 15 years after the conclusion of the contract or such time as the sum of such payments equals the remaining amount owed to the retail customers at the end of the contract, whichever is earlier. If the debt to the retail customers is not repaid within 15 years after the conclusion of the contract, then the owner of the clean coal SNG facility must sell the facility, and all proceeds from that sale must be used to repay any amount owed to the retail customers under this subsection (h-15).

The retail customers shall have first priority in recovering that debt above any creditors, except the secured lenders to the extent that the secured lenders have any secured debt outstanding, including any parent companies or affiliates of the clean coal SNG facility.

(3) 50% of all additional net revenue, defined as miscellaneous net revenue after cost allowance and above the budgeted estimate established for revenue pursuant to subsection (h), including sale of substitute natural gas derived from the clean coal SNG facility above the nameplate capacity of the facility and other by-products produced by the facility, shall be credited to the reconciliation account on an annual basis with such payment made within 30 days after the end of each calendar year during the term of the contract.

(4) The clean coal SNG facility shall each year, starting in the facility's first year of commercial operation, file with the Commission, in such form as the Commission shall require, a report as to the reconciliation account. The annual report must contain the following information:

(A) the revenue share target amount;

(B) the amount credited or debited to the reconciliation account during the year;

(C) the amount credited to the utilities to be used to reduce the utilities natural gas costs though the purchase gas adjustment clause;

(D) the total amount of reconciliation account at the beginning and end of the year;

(E) the total amount of consumer savings to date; and

(F) any additional information the Commission may require.

When any report is erroneous or defective or appears to the Commission to be erroneous or defective, the Commission may notify the clean coal SNG facility to amend the report within 30 days; before or after the termination of the 30-day period, the Commission may examine the trustee of the reconciliation account or the officers, agents, employees, books, records, or accounts of the clean coal SNG facility and correct such items in the report as upon such examination the Commission may find defective or erroneous. All reports shall be under oath.

All reports made to the Commission by the clean coal SNG facility and the contents of the reports shall be open to public inspection and shall be deemed a public record under the Freedom of Information Act. Such reports shall be preserved in the office of the Commission. The Commission shall publish an annual summary of the reports prior to February 1 of the following year. The annual summary shall be made available to the public on the Commission's website and shall be submitted to the General Assembly.

Any facility that fails to file the report required under this paragraph (4) to the Commission within the time specified or to make specific answer to any question propounded by the Commission within 30 days after the time it is lawfully required to do so, or within such further time not to exceed 90 days as may be allowed by the Commission in its discretion, shall pay a penalty of $500 to the Commission for each day it is in default.

Any person who willfully makes any false report to the Commission or to any member, officer, or employee thereof, any person who willfully in a report withholds or fails to provide material information to which the Commission is entitled under this paragraph (4) and which information is either required to be filed by statute, rule, regulation, order, or decision of the Commission or has been requested by the Commission, and any person who willfully aids or abets such person shall be guilty of a Class A misdemeanor.

(h-20) The General Assembly authorizes the Illinois Finance Authority to issue bonds to the maximum extent permitted to finance coal gasification facilities described in this Section, which constitute both "industrial projects" under Article 801 of the Illinois Finance Authority Act and "clean coal and energy projects" under Sections 825-65 through 825-75 of the Illinois Finance Authority Act.

Administrative costs incurred by the Illinois Finance Authority in performance of this subsection (h-20) shall be subject to reimbursement by the clean coal SNG facility on terms as the Illinois Finance Authority and the clean coal SNG facility may agree. The utility and its customers shall have no obligation to reimburse the clean coal SNG facility or the Illinois Finance Authority for any such costs.

(h-25) The State of Illinois pledges that the State may not enact any law or take any action to (1) break or repeal the authority for SNG purchase contracts entered into between public gas utilities and the clean coal SNG facility pursuant to subsection (h) of this Section or (2) deny public gas utilities their full cost recovery for contract costs, as defined in subsection (h-10), that are incurred under such SNG purchase contracts. These pledges are for the benefit of the parties to such SNG purchase contracts and the issuers and holders of bonds or other obligations issued or incurred to finance or refinance the clean coal SNG facility. The beneficiaries are authorized to include and refer to these pledges in any finance agreement into which they may enter in regard to such contracts.

(h-30) The State of Illinois retains and reserves all other rights to enact new or amendatory legislation or take any other action, including, but not limited to, such legislation or other action that would (1) directly or indirectly raise the costs that the clean coal SNG facility must incur; (2) directly or indirectly place additional restrictions, regulations, or requirements on the clean coal SNG facility; (3) prohibit sequestration in general or prohibit a specific sequestration method or project; or (4) increase minimum sequestration requirements.

(i) If a gas utility or an affiliate of a gas utility has an ownership interest in any entity that produces or sells synthetic natural gas, Article VII of this Act shall apply.

(Source: P.A. 96-1364, eff. 7-28-10; 97-96, eff. 7-13-11; 97-239, eff. 8-2-11; 97-630, eff. 12-8-11; 97-906, eff. 8-7-12; 97-1081, eff. 8-24-12; revised 1-24-13.)

(220 ILCS 5/9-244.5 new)

Sec. 9-244.5. Natural gas infrastructure investment and modernization; regulatory reform.

(a) 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 natural gas utility system. The General Assembly finds that natural gas 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 particular, the General Assembly finds that it is the policy of this State that significant investments must be made in the State's natural gas transmission and distribution system over the next 10 years to modernize and upgrade transmission and distribution facilities in the State. These investments will ensure that the State's natural gas utility infrastructure will promote future economic development and job creation in the State and that the State's natural gas utilities will be able to continue to provide quality natural gas service to their customers. These investments may include innovative technological offerings that will create and promote savings opportunities for customers by providing them with additional use of modern natural gas-fired appliances that will enhance customer experience and timely data that allows them to make more informed decisions concerning their gas usage and may enhance customers' ability to use energy efficient equipment dependent on a modernized system. Additionally these investments will also ensure that the State's gas transmission, distribution, and underground gas storage systems and related natural gas utility infrastructure are modernized and upgraded and continue 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 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 natural gas utilities and their customers, regulators, and investors.

(b) For purposes of this Section, "participating utility" means a natural gas utility serving fewer than 1,100,000 customers as of January 1, 2013, or a combination utility 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, 2012, provided electric service to at least 1,000,000 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. Illinois natural gas utilities that are affiliated by virtue of a common parent company, at the utilities' request, shall be considered a single gas utility for the sole purposes of determining: (1) if the utilities created the required number of full-time equivalent jobs and made the required level of investment under this subsection (b); (2) if the utilities exceeded the maximum level of investment under subsection (b-5) of this Section; (3) the required level of the utilities' contributions under subsection (b-10) of this Section; and (4) if these utilities have satisfied the performance metrics under subsection (f-2) of this Section.

During the infrastructure investment program's peak program year, a participating utility, other than a combination utility, serving fewer than 1,100,000 customers on January 1, 2013, shall create 1,000 full-time equivalent jobs in Illinois, such jobs measured by reference to the participating utility's average number of employees for the years 2008, 2009, and 2010 as reported in the applicable Form 21 ILCC and the participating utility's average number of contractor positions for the years 2008, 2009, and 2010 and related to the provision of natural gas service; and a participating utility that is a combination utility shall create 250 full-time equivalent jobs in Illinois, such jobs measured by reference to the participating utility's average number of employees for the years 2009, 2010, and 2011 as reported in the applicable Form 21 ILCC and the participating utility's total number of contractor positions as of December 31 of the year immediately preceding the 10-year investment period and related to the provision of natural gas service. These full-time equivalent jobs shall include direct jobs, contractor positions, and induced jobs. A portion of the full-time equivalent jobs created by each participating utility shall include incremental personnel not accounted for in the baseline calculated under this paragraph that have been subsequently hired or retained. 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 that is a combination utility files a performance-based formula rate tariff pursuant to subsection (c) of this Section the participating utility shall, except as otherwise provided in this subsection (b) over a 10-year period, invest an estimated $330,000,000 in gas transmission, distribution, and underground storage system upgrades, modernization and compliance projects, and training facilities, including, but not limited to:

(i) distribution plant, including mains, services, meters, regulators, measuring and regulating station equipment, and structures and improvements;

(ii) transmission plant, including mains, measuring and regulating station equipment, and structures and improvements;

(iii) underground storage plant, including compression station equipment and structures, measuring and regulating station structures and equipment, reservoirs, wells, lines, and gas purification equipment;

(iv) state of the art gas transmission and distribution control facility;

(v) training facilities;

(vi) gas advanced metering infrastructure meters including associated cyber secure data communication network; and

(vii) small volume transport.

(2) Beginning no later than 180 days after a participating utility serving fewer than 1,100,000 customers on January 1, 2013 that is not a combination utility files a performance-based formula rate tariff pursuant to subsection (c) of this Section the participating utility shall, except as otherwise provided in this subsection (b) over a 10-year period, invest an estimated $1,200,000,000 in gas transmission, distribution, and underground storage system upgrades, and modernization and compliance projects, including, but not limited to:

(i) distribution plant, including mains, services, meters, regulators, measuring and regulating station equipment, and structures and improvements;

(ii) transmission plant, including mains, measuring and regulating station equipment, and structures and improvements;

(iii) underground storage plant, including compression station equipment and structures, measuring and regulating station structures and equipment, reservoirs, wells, lines, and gas purification equipment; and

(iv) liquefied natural gas plant, including structures and improvements, gas holders, liquefaction equipment, and vaporizing equipment.

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 2009, 2010, and 2011 as reported in Form 21 ILCC, except in the case of a participating utility that is not a combination utility, serving fewer than 1,100,000 customers on January 1, 2013, for which the investments in the infrastructure 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 Form 21 ILCC; 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 Form 21 ILCC for the years 2009, 2010, and 2011, as applicable. A participating utility may add a 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 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 participating 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 participating 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 participating 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 program year 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 participating utility, the deficiency in the number of full time equivalent jobs during the peak program year due to such failure. The Commission shall notify the Department of any proceeding that is initiated pursuant to this paragraph. For each full time equivalent job deficiency during the peak program year that the Commission finds as set forth in this paragraph, the participating utility shall, within 30 days after the entry of the Commission's order, pay $6,000 to a fund for training grants administered under Section 605-800 of the Department of Commerce and Economic Opportunity Law, which shall not be a recoverable expense.

With respect to the participating utility's investment amount commitments, if, after considering the participating 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 participating 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 participating 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 participating 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 participating 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, 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, serving fewer than 1,100,000 customers on January 1, 2013, in satisfying its infrastructure investment program commitments described in subsection (b) of this Section exceed $2,500,000,000 or, for a participating utility that is a combination utility, $380,000,000. If the participating utility's updated cost estimates for satisfying its infrastructure investment program commitments described in subsection (b) exceed the limitation imposed by this paragraph, 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 participating 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 paragraph, then the participating utility may modify its plan so as not to exceed the limitation imposed by this paragraph, and may propose corresponding changes to the metrics established pursuant to subsection (f-1) or (f-2), as applicable, of this Section, and the Commission may modify the metrics and incremental savings goals established pursuant to subsection (f-1) or (f-2), as applicable, of this Section accordingly.

(b-10) All participating utilities shall make contributions for an energy low-income and support program or programs 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 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 shall pay $500,000 per year for 10 years to the energy low-income and support program or programs, 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 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 participating 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 98th General Assembly. The participating utility shall file annual reports documenting the disbursement of those funds under this Section 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 cost 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 participating 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 participating utility recovers a portion of its costs through automatic adjustment clause tariffs on the effective date of this amendatory Act of the 98th General Assembly, the participating utility may elect to continue to recover these costs through such automatic adjustment clause tariffs, but then these costs shall not be recovered through the performance-based formula rate, or the participating utility may elect to file at any time to terminate any or all such automatic adjustment clause tariffs and the Commission shall approve such filing no later than 45 days after such filing.

For purposes of this Section, including subsection (g), "delivery services" means those services provided by the gas utility that are necessary in order for the gas storage, transmission, and distribution systems to function so that retail customers located in the gas utility's service area can receive gas supply from the gas utility or, to the extent authorized by statute, Commission rule, or the gas utility's tariffs, from suppliers other than the gas utility, and shall include, without limitation, standard metering and billing services; provided, however, that solely for purposes of subsection (g), costs of delivery services shall not include charges assessed to retail customers under any tariff for recovery of costs of clean up or remediation of manufactured gas plant sites or any tariff for recovery of energy efficiency costs and excludes reconciliation adjustments determined under subsection (d) of this Section.

In the event the participating utility, prior to the effective date of this amendatory Act of the 98th General Assembly, filed gas delivery services tariffs with the Commission pursuant to Section 9-201 of this Act that are related to the recovery of its gas delivery services costs that are still pending on the effective date of this amendatory Act of the 98th General Assembly, the participating utility may, 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 gas 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 gas 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 gas delivery services except that the rate case expense incurred by the participating utility with respect to such tariffs through the date of dismissal of such docket shall be recoverable through the performance-based formula rate tariff, regardless of the year in which the rate case expense was incurred. The participating utility shall attest to the amount of the rate case expense by verification from an officer, and such amount shall not be disallowed.

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 customers, excluding customers taking service under contracts entered into pursuant to Section 9-102.1 of this Act. 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 participating utility. The performance-based formula rate approved by the Commission shall do the following:

(1) Provide for the recovery of the participating 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 participating utility's actual year-end capital structure for the applicable calendar year, excluding goodwill, subject to a determination of prudence and reasonableness consistent with Commission practice and law, except that the common equity ratio in the year-end capital structure for the applicable calendar year shall not be subject to a determination of prudence and reasonableness where said ratio is within 200 basis points of the common equity ratio approved by the Commission and reflected in the most recent Final Order resolving a participating utility's request for a general rate increase entered prior to the enactment of this Section.

(3) Include a cost of equity, which shall be calculated as the sum of the following:

(A) the average for the applicable calendar year of the monthly average yields of 30-year U.S. Treasury bonds published by the Board of Governors of the Federal Reserve System in its weekly H.15 Statistical Release or successor publication; and

(B) 580 basis points.

At such time as the Board of Governors of the Federal Reserve System ceases to include the monthly average yields of 30 year U.S. Treasury bonds in its weekly H.15 Statistical Release or successor publication, the monthly average yields of the U.S. Treasury bonds then having the longest duration published by the Board of Governors in its weekly H.15 Statistical Release or successor publication shall instead be used for purposes of this paragraph (3).

(4) Permit and set forth protocols, subject to a determination of prudence and reasonableness consistent with Commission practice and law, for the following:

(A) recovery of incentive compensation expense that is based on the achievement of operational metrics, including metrics related to budget controls, safety, customer service, efficiency and productivity, and environmental compliance, each of which may be measured specifically for the participating utility or for the corporation of which the participating utility is a part. 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, then the full amount shall be amortized consistent with subparagraph (F) of this paragraph (4) of this subsection (c);

(D) investment return at a rate equal to the utility's weighted average cost of long-term debt on the pension assets, net of deferred tax benefits, and on any associated regulatory asset. "Pension asset" means the excess, if any, of cumulative contributions by the utility to a pension trust over cumulative recognized pension expense. The "pension asset" is determined as the net of following items, where items (i) and (ii) combined represent the funded status of the participating utility's pension plans recognized on the participating utility's balance sheet, and where item (iii) represents the components of pension expense not yet recorded in earnings, but recognized separately on the participating utility's balance sheet:

(i) cumulative contributions made by the participating utility in a pension trust in compliance with its obligations under its defined benefit pension plans and any associated investment earnings, gains, and losses;

(ii) the participating utility's projected pension obligations calculated in accordance with U.S. Generally Accepted Accounting Principles;

(iii) the participating utility's pension-related regulatory assets or regulatory liabilities representing unrecognized components of pension cost and accounted for in accordance with U.S. Generally Accepted Accounting Principles;

(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 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 system event or other similar expense, provided that any unamortized balance shall be reflected in rate base. For purposes of this subparagraph (F), changes in law include 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 98th 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 paragraph (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 paragraph (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 annual reconciliations, as described in subsection (d) of this Section, with interest, of the delivery services component of revenue as reported in the applicable Form 21 ILCC, excluding any reconciliation adjustments under subsection (d) of this Section and any adjustments under paragraph (5) of subsection (c) of this Section, for each calendar year, beginning with the calendar year in which the participating 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 participating utility shall file, together with its tariff, final data based on its most recently filed Form 21 ILCC, 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 rates under the formula. For purposes of this Section, "Form 21 ILCC" means the Annual Report of Electric Utilities, Licensees and/or Natural Gas Utilities" or any successor to that report that natural gas utilities are required to file with the Commission under Section 5-109 of this Act. Nothing in this Section is intended to allow costs that are not otherwise recoverable to be recoverable by virtue of inclusion in Form 21 ILCC or to authorize the Commission to alter Form 21 ILCC in a manner that would result in a level of cost recovery inconsistent with the intent of this Section.

After the participating 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 98th General Assembly, then by May 31, 2014. 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 participating 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 methodology pursuant to subsection (e) of this Section, rate design and cost allocation methodology 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 participating 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) The participating 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 participating utility's most recently filed annual Form 21 ILCC, 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 delivery services component of revenue as reported in the applicable Form 21 ILCC, excluding any reconciliation adjustments under subsection (d) of this Section and any adjustments under paragraph (5) of subsection (c) of this Section, for each calendar year, beginning with the calendar year in which the participating utility files its performance-based formula rate tariff pursuant to subsection (c) of this Section, for the prior rate year with the actual revenue requirement for the prior rate year (determined using a year-end rate base) that uses amounts reflected in the applicable Form 21 ILCC that reports the actual costs for the prior rate year. Any over-collection or under-collection indicated by such reconciliations shall be reflected as a credit against, or recovered as an additional charge to, respectively, with interest calculated at a rate equal to the utility's weighted average cost of capital approved by the Commission for the prior rate year, the charges for the applicable rate year. Provided, however, that the first such reconciliation shall be for the calendar year in which the participating utility files its performance-based formula rate tariff pursuant to subsection (c) of this Section and shall reconcile (i) the delivery services component of revenue as reported in the applicable Form 21 ILCC for such calendar year with (ii) the revenue requirement determined using a year-end rate base for that calendar year calculated pursuant to the performance-based formula rate using (A) actual costs for that year as reflected in the applicable Form 21 ILCC, and, (B) for the first such reconciliation only, the cost of equity, which shall be calculated as the sum of 590 basis points plus the average for the applicable calendar year of the monthly average yields of 30-year U.S. Treasury bonds published by the Board of Governors of the Federal Reserve System in its weekly H.15 Statistical Release or successor publication. The first such reconciliation is not intended to provide for the recovery of costs previously excluded from rates based on a prior Commission order finding of imprudence or unreasonableness. Each reconciliation shall be certified by the participating utility in the same manner that Form 21 ILCC 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 reconciliations is to ultimately reconcile the delivery services component of revenue as reported in the applicable Form 21 ILCC for such calendar year, excluding any reconciliation adjustments under subsection (d) of this Section and any adjustments under paragraph (5) of subsection (c) of this Section, for each calendar year, beginning with the calendar year in which the participating utility files its performance-based formula rate tariff pursuant to subsection (c) of this Section, with what the revenue requirement determined using a year-end rate base for the applicable calendar year would have been had 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 participating 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 participating utility to be recovered during the applicable rate year that are reflected in the inputs to the performance-based formula rate derived from the participating utility's Form 21 ILCC. During the course of the hearing, each objection shall be stated with particularity and evidence provided in support thereof, after which the participating 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 participating 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 participating 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 participating 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 subsection (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 and cost allocation methodology of a performance-based formula rate that has been placed into effect for the participating utility. Following approval of a participating utility's performance-based formula rate tariff pursuant to subsection (c) of this Section, the participating 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 participating utility's filing. Following such approval, the participating 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 as follows:

(f-1) For each participating utility that is a combination utility, the following metrics shall be designed to achieve, ratably (i.e., in equal segments, unless otherwise specified) over a 10-year period, improvement over baseline performance values as follows:

(1) System Integrity Improvement (under 49 CFR Part 192): Reduce the number of outstanding, non-hazardous (Class 3) underground gas leaks on a participating utility's gas system by 20% using a baseline of 2012.

(2) System Integrity Improvement (under 49 CFR 192): Reduce the time period for leakage surveys on all distribution pipelines that operate at 250 psig or greater from every 5 years to once each calendar year, not to exceed 15 months, that are in a Class 3 or Class 4 Location.

(3) Public Education and Emergency Responders: 100% increase in the number of annual face to face informational and training meetings to enhance education and provide appropriate pipeline safety information to all stakeholders, including emergency responders, public officials, excavators, customers, safety advocates, and members of the public living in the vicinity of pipelines, using 2012 as a baseline.

(4) Third Party Excavation Damage: Reduce third party excavation damage with a 10% reduction in the number of damages per 1000 locate requests for natural gas facilities, using a baseline of 2012.

(5) Integrity Management: Beginning in year 2 of the participating utility's 10-year performance metric period, install or replace 65 miles of gas transmission pipeline facilities to upgrade and modernize the gas delivery infrastructure and establish records and maximum allowable operating pressures in accordance with Federal Department of Transportation regulations. Install automatic or remote controlled shut-off valves, or equivalent technology, where economically, technically, and operationally feasible on transmission pipelines constructed or entirely replaced.

(6) Gas System Performance Monitoring: Increase the number of new and upgraded gas transmission and distribution system remote monitoring devices by 20% to enhance and expand system pressure monitoring capabilities and data acquisition, using a baseline of 2012.

(7) Reduction in Issuance of Estimated Gas Bills: 50% improvement using a baseline of the average number of estimated gas bills for the years 2009 through 2011.

(8) 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 2011.

(f-2) For each participating utility serving fewer than 1,100,000 customers on January 1, 2013, that is not a combination utility, to achieve, over a 10-year period, improvement over baseline performance values as follows:

(1) System Integrity Improvement (under 49 CFR Part 192): Reduce the number of outstanding, non-hazardous (Class 3) underground gas leaks on a participating utility's gas system by 10% using a baseline of 2012.

(2) System Integrity Improvement: Reduce the number of bare steel, cast iron, ductile iron, copper and Cellulose Acetate Butyrate (CAB) plastic service pipes on a participating utility's gas system by 30% using a baseline of 2012.

(3) Public Education and Emergency Responders: 100% increase in the number of annual face to face informational and training meetings to enhance education and provide appropriate pipeline safety information to all stakeholders, including emergency responders, public officials, excavators, customers, safety advocates, and members of the public living in the vicinity of pipelines, using a baseline of 2012.

(4) Third Party Excavation Damage: Reduce third party excavation damage, with a 5% reduction in the number of damages per 1,000 locate requests for natural gas facilities, using a baseline of 2012.

(5) Integrity Management: Install 900 miles of gas pipeline facilities to upgrade and modernize the gas delivery infrastructure and establish records and maximum allowable operating pressures in accordance with the United States Department of Transportation regulations. Install automatic or remote controlled shut-off valves, or equivalent technology, where economically, technically, and operationally feasible, on transmission pipelines constructed or entirely replaced.

(6) Gas System Performance Monitoring: Increase the number of new and upgraded gas transmission and distribution system remote monitoring devices by 20% to enhance and expand system pressure monitoring capabilities and data acquisition, using a baseline of 2012.

(7) 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 2011.

The metrics shall include incremental performance goals for each year of the 10-year period, which shall be designed to demonstrate that the participating utility is on track to achieve the performance goal in each category at the end of the 10-year period. The participating utility shall elect when the 10-year period shall commence for the metrics set forth in this subsection (f), provided that it begins no later than 14 months following the date on which the participating utility begins investing pursuant to subsection (b) of this Section.

(f-5) The financial penalties applicable to the metrics described in subparagraphs (1) through (7) of subsection (f-1) 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 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 subparagraph (1) of subsection (f-1), for each year that a participating utility does not achieve each such goal, the participating utility's return of equity shall be reduced as follows: during year one, by 10 basis points; during years 2 and 3, by 5 basis points; during years 4 through 6, by 6 basis points; and during years 7 through 10, by 7 basis points.

(2) With respect to each of the incremental annual performance goals established pursuant to subparagraphs (2) and (6) of subsection (f-1), for each year that a participating utility does not achieve each such goal, the participating utility's return on equity shall be reduced as follows: during years one through 3, by 5 basis points; during years 4 through 6, by 6 basis points; and during years 7 through 10, by 7 basis points.

(3) With respect to each of the incremental annual performance goals established pursuant to subparagraph (5) of subsection (f-1), for each year that a participating utility does not achieve each such goal, the participating utility's return on equity shall be reduced as follows: during years 2 and 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 subparagraphs (3) and (4) of subsection (f-1), the performance under each goal shall be calculated in terms of the percentage of the goal achieved. The percentage 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 participating utility does not achieve an average percentage value for a given year of at least 100%, the participating utility's return on equity shall be reduced by 5 basis points.

(5) With respect to each of the incremental annual performance goals established pursuant to subparagraph (7) of subsection (f-1), for each year that a participating utility does not achieve each such goal, the participating utility's return on equity shall be reduced by 5 basis points.

(f-6) The financial penalties applicable to the metrics described in subparagraphs (1) through (6) of subsection (f-2) 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 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 subparagraphs (1), (2), (5), and (6) of subsection (f-2), for each year that a participating utility does not achieve each such goal, the participating utility's return on equity shall be reduced as follows: during years one 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.

(2) With respect to each of the incremental annual performance goals established pursuant to subparagraphs (3) and (4) of subsection (f-2), the performance under each goal shall be calculated in terms of the percentage of the goal achieved. The percentage 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 participating utility does not achieve an average percentage value for a given year of at least 100%, the participating utility's return on equity shall be reduced by 10 basis points.

(f-8) The financial penalties shall be applied as described in subsection (f-5) or (f-6), as applicable, for the 12-month period in which the deficiency occurred through a separate tariff mechanism, which shall be filed by the participating utility together with its metrics. In the event the performance-based formula rate tariff established pursuant to subsection (c) of this Section terminates, the participating utility's obligations under subsection (f-1) or (f-2), as applicable, and subsection (f-5) or (f-6), as applicable, of this Section and this subsection (f-8) shall also terminate, provided, however, that the tariff mechanism established pursuant to subsection (f) of this Section and subsection (f-5) or (f-6), as applicable, and this subsection (f-8) 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-1) or (f-2), as applicable, of this Section and subsection (f-5) or (f-6), as applicable, 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 participating utility's performance. Whenever a participating utility does not satisfy the metrics required pursuant to subsection (f-1) or (f-2), as applicable, of this Section, the Commission shall, after notice and hearing, enter an order approving financial penalties in accordance with subsection (f-5) or (f-6), as applicable, of this Section. 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 subparagraphs (1) through (3) of subsection (f-1) or (f-2), as applicable, of this Section.

(g) On or before June 30, 2016, each participating utility shall file a report with the Commission that calculates the 2-year average percentage change in the average residential retail customer's total bill over the 2-year period ended December 31, 2015, that is attributable to a change in delivery services charges, by comparing a base year and a comparison year pursuant to the methodology specified in this subsection (g). For a participating utility that is a combination utility with more than one rate zone, the weighted average aggregate change shall be provided. For a participating utility that has separate delivery service rates for space heat and non-space heat customers which are in effect in either or both the base year and the comparison year, the space heat rates, when applicable, shall be used for purposes of this calculation. 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.

For purposes of all calculations performed under this subsection (g), the average residential retail customer's assumed annual consumption, for the base year and the comparison year shall be assumed to be as follows: for a participating utility that is a combination utility, 785 therms; and for a participating utility that is not a combination utility and served fewer than 1,100,000 customers on January 1, 2013, 1,100 therms.

The report filed with the Commission shall:

(1) Calculate an average residential retail customer's total bill for natural gas service, expressed on a dollars per year basis, for a base year using: (i) the average residential retail customer's assumed annual consumption, (ii) a delivery service charge, using the delivery service rates in effect at the end of the December, 2013 billing cycle, and (iii) a cost of gas supply, based on the participating utility's average purchased gas adjustments for the period 2008-2010, where such total bill for natural gas service includes add-on taxes and riders.

(2) Calculate a delivery service charge for the base year, using the average residential customer's assumed annual consumption and the delivery service rates in effect at the end of the December, 2013 billing cycle, where such delivery service charge for natural gas service shall not include add-on taxes and riders.

(3) Calculate a delivery service charge for the comparison year, using the average residential customer's assumed annual consumption and the delivery service rates in effect at the end of the December, 2015 billing cycle, where such delivery service charge for natural gas service shall not include add-on taxes and riders. For purposes of the calculation of the delivery service charge for the comparison year any reconciliation adjustments determined under subsection (d) of this Section shall be excluded by multiplying each component of the delivery services rates by a fraction whose denominator is the revenue requirement that was used to derive the delivery service rates in effect at the end of the December, 2015 billing cycle and the numerator is this same revenue requirement adjusted to remove any reconciliation for previous years.

(4) Calculate the 2-year average change in the average residential retail customer's total bill attributable to a change in delivery service charges by subtracting the average residential retail customer's delivery service charge in the base year from the average residential retail customer's delivery service charge in the comparison year, and dividing the result by the average residential retail customer's total bill in the base year, and then dividing the resulting percentage by 2.

In the event that the average annual increase for a participating utility that is a combination utility exceeds 2.5% or for a participating utility that is not a combination utility exceeds 5%, as calculated pursuant to this subsection (g), then this Section of this Act, other than this subsection, shall be inoperative as it relates to the participating utility and its service area as of the date of the report due to be submitted pursuant to this subsection (g) and the participating 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 participating 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 or 5.0% or less, as applicable, as calculated pursuant to this subsection (g), then the performance-based formula rate shall remain in effect as set forth in this Section.

The fact that this Section becomes inoperative as set forth in this subsection (g) shall not be construed to mean that the Commission may reexamine or otherwise reopen prudence or reasonableness determinations already made.

(h) This Section, other than this subsection (h), and Section 19-150.6 of the Act, are inoperative after December 31, 2023, 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, 2023, 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 therm paid by residential customers, as defined in subsection (g) of this Section, between June 1, 2014 and May 31, 2023. The report shall include separate sections for each participating utility. 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) Nothing in this Section is intended to legislatively overturn the opinion issued in People ex rel. Lisa Madigan v. Ill. Commerce Comm'n, Nos. 1-10-0936, 1-10-1790, 1-10-1846, and 1-10-1852 cons. (Ill. App. Ct. 1st Dist. Sept. 30, 2011). This amendatory Act of the 98th 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.

(j) 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 Gas AMI functionality or application to its retail customers, including, but not limited to, the installation, implementation and maintenance of Gas AMI system upgrades as defined in Section 19-150.6 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 Gas AMI functionality or applications as defined in Section 19-150.6 of this Act, and from recovering the costs of such offerings from retail customers.

(220 ILCS 5/19-150.6 new)

Sec. 19-150.6. Provisions relating to Gas Advanced Metering Infrastructure Deployment Plan.

(a) For purposes of this Section:

"Gas Advanced Metering Infrastructure" or "Gas AMI" means the communications hardware and software and associated system software that creates a network between advanced gas meters and utility business systems and allows the collection and distribution of gas-related information to customers and other parties in addition to providing information to the utility itself.

"Gas Advanced Metering Infrastructure Benefits" may include, but are not limited to, the following:

(1) Reduction in estimated gas bills.

(2) Reduction in monthly and off-cycle meter reading costs.

(3) Reduction in meter reprogramming costs due to remote programmability.

(4) Reduction in unmetered and unbilled usage due to earlier identification of meter problems and tampering.

(5) Reduction in vehicle emissions due to reduction in manual meter reading.

(6) Improved and more timely information available to customers to assist with energy management and cost savings.

(7) Improved information for the development of new energy efficiency programs.

(8) Improved information for more efficient gas system operation.

(9) Improved safety of gas operations.

"Cost-beneficial" means a determination that the benefits of a participating utility's Gas AMI Deployment Plan exceed the costs of the 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 Gas AMI Deployment Plan exceeds the present value of the total costs of the Gas AMI Deployment Plan. The total cost shall include all utility costs reasonably associated with the Gas AMI Deployment Plan. The total benefits shall include the sum of avoided costs, including avoided utility operational costs, avoided consumer commodity costs, and avoided societal costs associated with the production and consumption of natural gas, as well as other societal benefits, including reductions in the emissions of harmful pollutants and associated avoided health-related costs, other benefits associated with natural gas energy efficiency measures.

"Participating utility" has the meaning set forth in Section 9-244.5 of this Act.

(b) Each participating utility that has an investment plan including Gas AMI under Section 9-244.5 of this Act shall file a Gas AMI Deployment Plan with the Commission within 180 days after the filing of a tariff pursuant to subsection (c) of Section 9-244.5. The Gas AMI Deployment Plan shall provide for investment over a 10-year period that is sufficient to implement the Gas AMI Deployment Plan across its entire delivery service territory in a manner that is consistent with subsection (b) of Section 9-244.5 of this Act. The Gas AMI Deployment Plan shall contain:

(1) the participating utility's Gas AMI vision statement that is consistent with the goal of developing a cost-beneficial Advanced Gas Metering Infrastructure;

(2) a statement of Gas AMI strategy that includes a description of how the participating utility evaluates and prioritizes technology choices to create customer value, including a plan to enhance and enable customers' ability to take advantage of Gas AMI functionality beginning at the time an account has billed successfully on the Gas AMI network;

(3) a deployment schedule and plan that includes deployment of Gas AMI to all customers for a participating utility other than a combination utility, and to 56% 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 Gas AMI Deployment Plan in enabling Gas AMI functionality; and enhancing consumer benefits from gas system upgrades; and

(5) a plan for consumer education to be implemented by the participating utility.

The Gas AMI Deployment 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 gas 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 Gas AMI Deployment 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 a Gas AMI Deployment Plan, issue its order approving, or approving with modification, the Gas AMI Deployment Plan if the Commission finds that the Gas AMI Deployment Plan contains the information required in paragraphs (1) through (5) of this subsection (b) and further finds that the implementation of the Gas AMI Deployment Plan is likely to be cost-beneficial. A participating utility's decision to invest pursuant to a Gas AMI Deployment Plan approved by the Commission shall not be subject to prudence reviews in subsequent Commission proceedings. Nothing in this subsection (b) is intended to limit the Commission's ability to review the reasonableness of the costs incurred under the Gas AMI Deployment Plan. A participating utility shall be allowed to recover the reasonable costs it incurs in implementing a Commission-approved Gas AMI Deployment Plan, including the costs of retired meters and radio modules, and may recover such costs through its tariffs, including the performance-based formula rate tariff approved pursuant to subsection (c) of Section 9-244.5 of this Act.

(c) The Gas AMI Deployment 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 or other personally identifying information, as well as information about the customer's natural gas usage. Utilities, their contractors or agents, and any third party who comes into possession of such personal information 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 participating utility's business. Utilities shall comply with the consumer privacy requirements of the Personal Information Protection Act that are in effect as of the effective date of this amendatory Act of the 98th General Assembly and as amended thereafter.

(d) On April 1 of each year beginning the year following approval of the participating utility's Gas AMI Deployment Plan, each participating utility that has an investment plan including Gas AMI under Section 9-244.5 of this Act shall submit a report regarding the progress it has made toward completing implementation of its Gas AMI Deployment Plan. This report shall:

(1) describe the Gas AMI investments made during the prior 12 months and the Gas AMI investments planned to be made in the following 12 months;

(2) provide sufficient detail to determine the participating utility's progress in meeting the metrics and milestones identified by the participating utility in its Gas AMI Deployment Plan; and

(3) identify any updates to the Gas AMI Deployment Plan.

Within 21 days after the participating 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 participating utility's progress in implementing the Gas AMI Deployment Plan as described in paragraph (1) of this subsection (d). If the Commission finds, after notice and hearing, that the participating utility's progress in implementing the Gas AMI Deployment 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 Gas AMI Deployment Plan. The Commission's order must be entered within 90 days after the participating utility files its annual report. If the Commission does not initiate an investigation within 21 days after the participating utility files its annual report, then the filing shall be deemed accepted by the Commission. The participating utility shall not be required to suspend implementation of its Gas AMI Deployment Plan during any Commission investigation.

The participating utility's annual report regarding Gas AMI Deployment Plan year 10 shall contain a statement verifying that the implementation of its Gas AMI Deployment Plan is complete, provided, however, that if the participating utility is subject to a corrective action plan that extends the implementation period beyond 10 years, the participating 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 participating utility's annual reporting obligations under this subsection (d) shall terminate, provided, however, that the participating utility shall have a continuing obligation to provide information, upon request, to the Commission regarding the Gas AMI Deployment Plan.

(h) If Section 9-244.5 of this Act becomes inoperative with respect to one or more participating utilities as set forth in subsection (g) of that Section, then Sections 9-244.5 and 19-150.6 of this Act, other than this Section, shall become inoperative as to each affected participating utility and its service area on the same date as Section 9-244.5.

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