SB2169enr 97TH GENERAL ASSEMBLY

SB2169 Enrolled LRB097 07925 ASK 48040 b

AN ACT concerning regulation.

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

Section 5. The Illinois Power Agency Act is amended by changing Section 1-10 as follows:

(20 ILCS 3855/1-10)

Sec. 1-10. Definitions.

"Agency" means the Illinois Power Agency.

"Agency loan agreement" means any agreement pursuant to which the Illinois Finance Authority agrees to loan the proceeds of revenue bonds issued with respect to a project to the Agency upon terms providing for loan repayment installments at least sufficient to pay when due all principal of, interest and premium, if any, on those revenue bonds, and providing for maintenance, insurance, and other matters in respect of the project.

"Authority" means the Illinois Finance Authority.

"Clean coal facility" means an electric generating facility that uses primarily coal as a feedstock and that captures and sequesters carbon dioxide emissions at the following levels: at least 50% of the total carbon dioxide emissions that the facility would otherwise emit if, at the time construction commences, the facility is scheduled to commence operation before 2016, at least 70% of the total carbon dioxide emissions that the facility would otherwise emit if, at the time construction commences, the facility is scheduled to commence operation during 2016 or 2017, and at least 90% of the total carbon dioxide emissions that the facility would otherwise emit if, at the time construction commences, the facility is scheduled to commence operation after 2017. The power block of the clean coal facility shall not exceed allowable emission rates for sulfur dioxide, nitrogen oxides, carbon monoxide, particulates and mercury for a natural gas-fired combined-cycle facility the same size as and in the same location as the clean coal facility at the time the clean coal facility obtains an approved air permit. All coal used by a clean coal facility shall have high volatile bituminous rank and greater than 1.7 pounds of sulfur per million btu content, unless the clean coal facility does not use gasification technology and was operating as a conventional coal-fired electric generating facility on June 1, 2009 (the effective date of Public Act 95-1027).

"Clean coal SNG facility" means a facility that uses a gasification process to produce substitute natural gas, that sequesters at least 90% of the total carbon emissions that the facility would otherwise emit, and that uses at least 90% petroleum coke or coal as a feedstock, with all such coal having a high bituminous rank and greater than 1.7 pounds of sulfur per million btu content, and that has a valid and effective permit to construct emission sources and air pollution control equipment and approval with respect to the federal regulations for Prevention of Significant Deterioration of Air Quality (PSD) for the plant pursuant to the federal Clean Air Act.

"Commission" means the Illinois Commerce Commission.

"Costs incurred in connection with the development and construction of a facility" means:

(1) the cost of acquisition of all real property, fixtures, and improvements in connection therewith and equipment, personal property, and other property, rights, and easements acquired that are deemed necessary for the operation and maintenance of the facility;

(2) financing costs with respect to bonds, notes, and other evidences of indebtedness of the Agency;

(3) all origination, commitment, utilization, facility, placement, underwriting, syndication, credit enhancement, and rating agency fees;

(4) engineering, design, procurement, consulting, legal, accounting, title insurance, survey, appraisal, escrow, trustee, collateral agency, interest rate hedging, interest rate swap, capitalized interest, contingency, as required by lenders, and other financing costs, and other expenses for professional services; and

(5) the costs of plans, specifications, site study and investigation, installation, surveys, other Agency costs and estimates of costs, and other expenses necessary or incidental to determining the feasibility of any project, together with such other expenses as may be necessary or incidental to the financing, insuring, acquisition, and construction of a specific project and starting up, commissioning, and placing that project in operation.

"Department" means the Department of Commerce and Economic Opportunity.

"Director" means the Director of the Illinois Power Agency.

"Demand-response" means measures that decrease peak electricity demand or shift demand from peak to off-peak periods.

"Energy efficiency" means measures that reduce the amount of electricity or natural gas required to achieve a given end use.

"Electric utility" has the same definition as found in Section 16-102 of the Public Utilities Act.

"Facility" means an electric generating unit or a co-generating unit that produces electricity along with related equipment necessary to connect the facility to an electric transmission or distribution system.

"Governmental aggregator" means one or more units of local government that individually or collectively procure electricity to serve residential retail electrical loads located within its or their jurisdiction.

"Local government" means a unit of local government as defined in Article VII of Section 1 of the Illinois Constitution.

"Municipality" means a city, village, or incorporated town.

"Person" means any natural person, firm, partnership, corporation, either domestic or foreign, company, association, limited liability company, joint stock company, or association and includes any trustee, receiver, assignee, or personal representative thereof.

"Project" means the planning, bidding, and construction of a facility.

"Public utility" has the same definition as found in Section 3-105 of the Public Utilities Act.

"Real property" means any interest in land together with all structures, fixtures, and improvements thereon, including lands under water and riparian rights, any easements, covenants, licenses, leases, rights-of-way, uses, and other interests, together with any liens, judgments, mortgages, or other claims or security interests related to real property.

"Renewable energy credit" means a tradable credit that represents the environmental attributes of a certain amount of energy produced from a renewable energy resource.

"Renewable energy resources" includes energy and its associated renewable energy credit or renewable energy credits from wind, solar thermal energy, photovoltaic cells and panels, biodiesel, crops and untreated and unadulterated organic waste biomass, tree waste, hydropower that does not involve new construction or significant expansion of hydropower dams, and other alternative sources of environmentally preferable energy. For purposes of this Act, landfill gas produced in the State is considered a renewable energy resource. "Renewable energy resources" does not include the incineration or burning of tires, garbage, general household, institutional, and commercial waste, industrial lunchroom or office waste, landscape waste other than tree waste, railroad crossties, utility poles, or construction or demolition debris, other than untreated and unadulterated waste wood.

"Revenue bond" means any bond, note, or other evidence of indebtedness issued by the Authority, the principal and interest of which is payable solely from revenues or income derived from any project or activity of the Agency.

"Sequester" means permanent storage of carbon dioxide by injecting it into a saline aquifer, a depleted gas reservoir, or an oil reservoir, directly or through an enhanced oil recovery process that may involve intermediate storage, regardless of whether these activities are conducted by a clean coal facility, a clean coal SNG facility, or a party with which a clean coal facility or clean coal SNG facility has contracted for such purposes in a salt dome.

"Servicing agreement" means (i) in the case of an electric utility, an agreement between the owner of a clean coal facility and such electric utility, which agreement shall have terms and conditions meeting the requirements of paragraph (3) of subsection (d) of Section 1-75, and (ii) in the case of an alternative retail electric supplier, an agreement between the owner of a clean coal facility and such alternative retail electric supplier, which agreement shall have terms and conditions meeting the requirements of Section 16-115(d)(5) of the Public Utilities Act.

"Substitute natural gas" or "SNG" means a gas manufactured by gasification of hydrocarbon feedstock, which is substantially interchangeable in use and distribution with conventional natural gas.

"Total resource cost test" or "TRC test" means a standard that is met if, for an investment in energy efficiency or demand-response measures, the benefit-cost ratio is greater than one. The benefit-cost ratio is the ratio of the net present value of the total benefits of the program to the net present value of the total costs as calculated over the lifetime of the measures. A total resource cost test compares the sum of avoided electric utility costs, representing the benefits that accrue to the system and the participant in the delivery of those efficiency measures, as well as other quantifiable societal benefits, including avoided natural gas utility costs, to the sum of all incremental costs of end-use measures that are implemented due to the program (including both utility and participant contributions), plus costs to administer, deliver, and evaluate each demand-side program, to quantify the net savings obtained by substituting the demand-side program for supply resources. In calculating avoided costs of power and energy that an electric utility would otherwise have had to acquire, reasonable estimates shall be included of financial costs likely to be imposed by future regulations and legislation on emissions of greenhouse gases.

(Source: P.A. 95-481, eff. 8-28-07; 95-913, eff. 1-1-09; 95-1027, eff. 6-1-09; 96-33, eff. 7-10-09; 96-159, eff. 8-10-09; 96-784, eff. 8-28-09; 96-1000, eff. 7-2-10.)

Section 10. The Illinois Procurement Code is amended by changing Section 1-10 as follows:

(30 ILCS 500/1-10)

Sec. 1-10. Application.

(a) This Code applies only to procurements for which contractors were first solicited on or after July 1, 1998. This Code shall not be construed to affect or impair any contract, or any provision of a contract, entered into based on a solicitation prior to the implementation date of this Code as described in Article 99, including but not limited to any covenant entered into with respect to any revenue bonds or similar instruments. All procurements for which contracts are solicited between the effective date of Articles 50 and 99 and July 1, 1998 shall be substantially in accordance with this Code and its intent.

(b) This Code shall apply regardless of the source of the funds with which the contracts are paid, including federal assistance moneys. This Code shall not apply to:

(1) Contracts between the State and its political subdivisions or other governments, or between State governmental bodies except as specifically provided in this Code.

(2) Grants, except for the filing requirements of Section 20-80.

(3) Purchase of care.

(4) Hiring of an individual as employee and not as an independent contractor, whether pursuant to an employment code or policy or by contract directly with that individual.

(5) Collective bargaining contracts.

(6) Purchase of real estate, except that notice of this type of contract with a value of more than $25,000 must be published in the Procurement Bulletin within 7 days after the deed is recorded in the county of jurisdiction. The notice shall identify the real estate purchased, the names of all parties to the contract, the value of the contract, and the effective date of the contract.

(7) Contracts necessary to prepare for anticipated litigation, enforcement actions, or investigations, provided that the chief legal counsel to the Governor shall give his or her prior approval when the procuring agency is one subject to the jurisdiction of the Governor, and provided that the chief legal counsel of any other procuring entity subject to this Code shall give his or her prior approval when the procuring entity is not one subject to the jurisdiction of the Governor.

(8) Contracts for services to Northern Illinois University by a person, acting as an independent contractor, who is qualified by education, experience, and technical ability and is selected by negotiation for the purpose of providing non-credit educational service activities or products by means of specialized programs offered by the university.

(9) Procurement expenditures by the Illinois Conservation Foundation when only private funds are used.

(10) Procurement expenditures by the Illinois Health Information Exchange Authority involving private funds from the Health Information Exchange Fund. "Private funds" means gifts, donations, and private grants.

(c) This Code does not apply to the electric power procurement process provided for under Section 1-75 of the Illinois Power Agency Act and Section 16-111.5 of the Public Utilities Act.

(d) Except for Section 20-160 and Article 50 of this Code, and as expressly required by Section 9.1 of the Illinois Lottery Law, the provisions of this Code do not apply to the procurement process provided for under Section 9.1 of the Illinois Lottery Law.

(e) This Code does not apply to the processes used by the Illinois Power Agency to retain a mediator to mediate contract disputes between gas utilities and the clean coal SNG facility and to retain an expert to assist in the review of contracts under subsection (h) of Section 9-220 of the Public Utilities Act. This Code does not apply to the process used by the Illinois Commerce Commission to retain an expert to assist in determining the actual incurred costs of the clean coal SNG facility and the reasonableness of those costs as required under subsection (h) of Section 9-220 of the Public Utilities Act.

(Source: P.A. 95-481, eff. 8-28-07; 95-615, eff. 9-11-07; 95-876, eff. 8-21-08; 96-840, eff. 12-23-09; 96-1331, eff. 7-27-10.)

Section 15. The Public Utilities Act is amended by changing Sections 3-101 and 9-220 and by adding Sections 3-123, 3-124, 3-125, and 3-126 as follows:

(220 ILCS 5/3-101) (from Ch. 111 2/3, par. 3-101)

Sec. 3-101. Definitions. Unless otherwise specified, the terms set forth in Sections 3-102 through 3-126 3-121 are used in this Act as therein defined.

(Source: P.A. 84-617; 84-1118.)

(220 ILCS 5/3-123 new)

Sec. 3-123. Clean coal facility; clean coal SNG facility; sequester; SNG facility; substitute natural gas or SNG. As used in this Act:

"Clean coal facility" shall have the same meaning as provided in Section 1-10 of the Illinois Power Agency Act.

"Clean coal SNG facility" shall have the same meaning as provided in Section 1-10 of the Illinois Power Agency Act.

"Sequester" shall have the same meaning as provided in Section 1-10 of the Illinois Power Agency Act.

"SNG facility" means a facility that produces substitute natural gas from feedstock that includes coal through a gasification process, including a clean coal facility, and the clean coal SNG facility.

"Substitute natural gas" or "SNG" shall have the same meaning as provided in Section 1-10 of the Illinois Power Agency Act.

(220 ILCS 5/3-124 new)

Sec. 3-124. Adjusted final capitalized plant cost. "Adjusted final capitalized plant cost" means the final capitalized plant cost reduced by the following, without duplication and to the extent not already accounted for or reflected on the books of the facility: (1) any State of Illinois financial assistance, (2) any U.S. financial assistance, and (3) any quantifiable benefit from a U.S. Clean Coal Gasification Program received by the facility during a period equal to the shorter of (A) the life of such program or (B) the term of the agreement, such quantifiable benefit to be discounted at a rate of 14% per annum over such period.

(220 ILCS 5/3-125 new)

Sec. 3-125. Final capitalized plant cost. "Final capitalized plant cost" means the total capitalized asset cost of the plant of the clean coal SNG facility as reflected on the balance sheet of the facility at the time of the commercial production date, with such capitalized cost to be accrued in accordance with generally accepted accounting principles, and includes, without limitation, the following items: major equipment, the SNG pipeline from the plant to the receiving pipeline, water lines, railroad improvements, access road improvements, all coal transportation assets, including the slurry line, slurry prep plant, carbon dioxide capture metering and compression, licensing fees, all costs incurred in the management planning, oversight and execution of the construction and start-up of the plant, and all fees and costs payable under engineering, procurement, and design contracts for the construct of the plant accrued as of the time of the commercial production date, but does not include capitalized financing costs including capitalized interest during construction and all fees associated with financing, coal reserve leasing costs, marketing, training, any and all costs payable under the contract miner agreement, the cost of coal mining equipment and similar costs, and any other costs, including general and administrative costs, not reasonably incurred in connection with the design, construction, testing, start-up, or commissioning of the plant in preparation for commercial production date.

(220 ILCS 5/3-126 new)

Sec. 3-126. Total capitalized asset cost. "Total capitalized asset cost" means the gross book value of the plant, as determined in accordance with generally accepted accounting principles at the commercial production date.

(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 March 31, 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 gasification facility by July 1, 2012 in Jefferson County 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 the only coal to be used in the gasification process shall be coal with a has 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 aggregate long-term supply contract contracts for the purchase of SNG does not exceed 15% 25% of the annual system supply requirements of the utility as of 2008 and the quantity of SNG supplied to a utility may not exceed 16 million MMBtus; 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 per year.

Any gas utility that is providing service to more than 150,000 customers on the effective date of this amendatory Act of the 97th General Assembly 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 the effective date of this amendatory Act of the 97th General Assembly 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.

Within 7 days after the effective date of this amendatory Act of the 97th General Assembly, 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 the effective date of this amendatory Act of the 97th General Assembly 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 the effective date of this amendatory Act of the 97th General Assembly.

The Illinois Power Agency shall complete all of its responsibilities under this subsection (h) within 60 days after the effective date of this amendatory Act of the 97th General Assembly. 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-5) All contracts entered into under subsection (h) of this Section, regardless of duration, shall require the owner of any facility supplying SNG under the contract 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.

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 Act 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 Act 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.

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.

(h-7) Sequestration permitting, oversight, and investigations. No clean coal 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.

The Commission shall review carbon dioxide transportation and sequestration methods proposed by a clean coal 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, 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 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) 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.

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 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.

At least annually, the Commission shall inspect all carbon dioxide pipelines in Illinois that transport carbon dioxide to ensure the safety and feasibility of those pipelines. The Commission may, as often as deemed necessary, monitor and conduct investigations of those pipelines. The owner or operator of the pipeline must cooperate with the Commission investigations of the carbon dioxide pipelines.

In circumstances whereby a carbon dioxide pipeline creates a substantial danger to the environment or to the public health of persons or to the welfare of persons where such danger is to the livelihood of such persons, the State's Attorney or Attorney General, upon the request of the Commission or on his or her own motion, may institute a civil action for an immediate injunction to halt any discharge or other activity causing or contributing to the danger or to require such other action as may be necessary. The court may issue an ex parte order and shall schedule a hearing on the matter not later than 3 working days after the date of injunction. The Commission 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 a utility or its customers.

(h-5) The Attorney General, on behalf of the people of the State of Illinois, may specifically enforce the requirements of this subsection (h-5). All contracts, regardless of duration, shall require the owner of any facility supplying SNG under the contract to provide 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. If, in any year, the owner of the 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 facility must offset excess emissions. Any such carbon dioxide offsets must be permanent, additional, verifiable, real, located within the State of Illinois, and legally and practicably enforceable; provided that the owner of the facility shall not be obligated to acquire carbon dioxide emission offsets to the extent that the cost of acquiring such offsets would exceed $40 million in any given year. No costs of any purchases of carbon offsets may be recovered from a utility or its customers. All carbon offsets purchased for this purpose must be permanently retired. In addition, carbon dioxide emission credits equivalent to 50% of the amount of credits associated with the required sequestration of carbon dioxide from the facility must be permanently retired. Compliance with the sequestration requirements and the offset purchase requirements specified in this subsection (h-5) shall be assessed annually by an independent expert retained by the owner of the SNG facility, with the advance written approval of the Attorney General. A SNG facility operating pursuant to this subsection (h-5) shall not forfeit its designation as a clean coal SNG facility if the facility fails to fully comply with the applicable carbon sequestration requirements in any given year, provided the requisite offsets are purchased.

(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) (h-20) 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) (h-20) 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-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.

With respect to each contract entered into by the company with an Illinois utility in accordance with the terms stated in subsection (h) of this Section, within 60 days following the completion of purchases of SNG, the Illinois Power Agency shall conduct an analysis to determine (i) the average contract SNG cost, which shall be calculated as the total amount paid to a company for SNG over the contract term, 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 under the utility contract; (ii) the average natural gas purchase cost, which shall be calculated as the total annual supply costs paid for natural gas (excluding SNG) purchased by such utility over the contract term, 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 natural gas (excluding SNG) actually purchased by the utility during the contract term; (iii) the cost differential, which shall be the difference between the average contract SNG cost and the average natural gas purchase cost; and (iv) the revenue share target, which shall be the cost differential multiplied by the total amount of SNG purchased under such utility contract. If the average contract SNG cost is equal to or less than the average natural gas purchase cost, then the company shall have no further obligation to the utility. If the average contract SNG cost for such SNG contract is greater than the average natural gas purchase cost for such utility, then the company shall market the daily production of SNG and distribute on a monthly basis 5% of amounts collected with respect to such future sales to the utilities in proportion to each utility's SNG purchases from the company during the term of the SNG contract to be used to reduce the utility's natural gas costs through the purchased gas adjustment clause; such payments to the utility shall continue until such time as the sum of such payments equals the revenue share target of that utility. The company or utilities shall have no obligation to repay the revenue share target except as provided for in this subsection (h-15).

(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. The General Assembly further authorizes the Illinois Power Agency to become party to agreements and take such actions as necessary to enable the Illinois Power Agency or its designate to (i) review and confirm in writing that the terms stated in subsection (h) of this Section are incorporated in the SNG contract, and (ii) conduct an analysis pursuant to subsection (h-15) of this Section.

Administrative costs incurred by the Illinois Finance Authority and Illinois Power Agency in performance of this subsection (h-20) shall be subject to reimbursement by the clean coal SNG facility company on terms as the Illinois Finance Authority, the Illinois Power Agency, and the clean coal SNG facility company may agree. The utility and its customers shall have no obligation to reimburse the clean coal SNG facility or company, the Illinois Finance Authority, or the Illinois Power Agency 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. 95-1027, eff. 6-1-09; 96-1364, eff. 7-28-10.)

Section 20. The Illinois Gas Pipeline Safety Act is amended by changing Sections 2.02, 2.03, 2.04, and 3 as follows:

(220 ILCS 20/2.02) (from Ch. 111 2/3, par. 552.2)

Sec. 2.02.

"Gas" means natural gas, flammable gas or gas which is toxic or corrosive. "Gas" also means carbon dioxide in any physical form, whenever transported by pipeline for the purpose of sequestration.

(Source: P.A. 76-1588.)

(220 ILCS 20/2.03) (from Ch. 111 2/3, par. 552.3)

Sec. 2.03. "Transportation of gas" means the gathering, transmission, or distribution of gas by pipeline or its storage, within this State and not subject to the jurisdiction of the Federal Energy Regulatory Commission under the Natural Gas Act, except that it includes the transmission of gas through pipeline facilities within this State that transport gas from an interstate gas pipeline to a direct sales customer within this State purchasing gas for its own consumption. "Transportation of gas" also includes the conveyance of gas from a gas main through the primary fuel line to the outside wall of residential premises. If the gas meter is placed within 3 feet of the structure, the utility's responsibility shall end at the outlet side of the meter. "Transportation of gas" also includes the conveyance of carbon dioxide in any physical form for the purpose of sequestration.

(Source: P.A. 87-1092; 88-314.)

(220 ILCS 20/2.04) (from Ch. 111 2/3, par. 552.4)

Sec. 2.04. "Pipeline facilities" includes new and existing pipe rights-of-way and any equipment, facility, or building used in the transportation of gas or the treatment of gas during the course of transportation and includes facilities within this State that transport gas from an interstate gas pipeline to a direct sales customer within this State purchasing gas for its own consumption, but "rights-of-way" as used in this Act does not authorize the Commission to prescribe, under this Act, the location or routing of any pipeline facility. "Pipeline facilities" also includes new and existing pipes and lines and any other equipment, facility, or structure, except customer-owned branch lines connected to the primary fuel lines, used to convey gas from a gas main to the outside wall of residential premises, and any person who provides gas service directly to its residential customer through these facilities shall be deemed to operate such pipeline facilities for purposes of this Act irrespective of the ownership of the facilities or the location of the facilities with respect to the meter, except that a person who provides gas service to a "master meter system", as that term is defined at 49 C.F.R. Section 191.3, shall not be deemed to operate any facilities downstream of the master meter. "Pipeline facilities" also includes new and existing pipe rights-of-way and any equipment, facility, or building used in the transportation of carbon dioxide in any physical form for the purpose of sequestration.

(Source: P.A. 87-1092; 88-314.)

(220 ILCS 20/3) (from Ch. 111 2/3, par. 553)

Sec. 3. (a) As soon as practicable, but not later than 3 months after the effective date of this Act, the Commission shall adopt rules establishing minimum safety standards for the transportation of gas and for pipeline facilities. Such rules shall be at least as inclusive, as stringent, and compatible with, the minimum safety standards adopted by the Secretary of Transportation under the Federal Act. Thereafter, the Commission shall maintain such rules so that the rules are at least as inclusive, as stringent, and compatible with, the minimum standards from time to time in effect under the Federal Act. The Commission shall also adopt rules establishing minimum safety standards for the transportation of carbon dioxide in any physical form for the purpose of sequestration and for pipeline facilities used for that function.

(b) Standards established under this Act may apply to the design, installation, inspection, testing, construction, extension, operation, replacement, and maintenance of pipeline facilities. Standards affecting the design, installation, construction, initial inspection and initial testing are not applicable to pipeline facilities in existence on the date such standards are adopted. Whenever the Commission finds a particular facility to be hazardous to life or property, it may require the person operating such facility to take the steps necessary to remove the hazard.

(c) Standards established by the Commission under this Act shall, subject to paragraphs (a) and (b) of this Section 3, be practicable and designed to meet the need for pipeline safety. In prescribing such standards, the Commission shall consider: similar standards established in other states; relevant available pipeline safety data; whether such standards are appropriate for the particular type of pipeline transportation; the reasonableness of any proposed standards; and the extent to which such standards will contribute to public safety.

Rules adopted under this Act are subject to "The Illinois Administrative Procedure Act", approved September 22, 1975, as amended.

(Source: P.A. 83-333.)

Section 25. The Environmental Protection Act is amended by adding Section 13.7 as follows:

(415 ILCS 5/13.7 new)

Sec. 13.7. Carbon dioxide sequestration sites.

(a) For purposes of this Section, the term "carbon dioxide sequestration site" means a site or facility for which the Agency has issued a permit for the underground injection of carbon dioxide.

(b) The Agency shall inspect carbon dioxide sequestration sites for compliance with this Act, rules adopted under this Act, and permits issued by the Agency.

(c) If the Agency issues a seal order under Section 34 of this Act in relation to a carbon dioxide sequestration site, or if a civil action for an injunction to halt activity at a carbon dioxide sequestration site is initiated under Section 43 of this Act at the request of the Agency, then the Agency shall post notice of such action on its website.

(d) Persons seeking a permit or permit modification for the underground injection of carbon dioxide shall be liable to the Agency for all reasonable and documented costs incurred by the Agency that are associated with review and issuance of the permit, including, but not limited to, costs associated with public hearings and the review of permit applications. Once a permit is issued, the permittee shall be liable to the Agency for all reasonable and documented costs incurred by the Agency that are associated with inspections and other oversight of the carbon dioxide sequestration site. Persons liable for costs under this subsection (d) must pay the costs upon invoicing, or other request or demand for payment, by the Agency. Costs for which a person is liable under this subsection (d) are in addition to any other fees, penalties, or other relief provided under this Act or any other law.

Moneys collected under this subsection (d) shall be deposited into the Environmental Protection Permit and Inspection Fund established under Section 22.8 of this Act. The Agency may adopt rules relating to the collection of costs due under this subsection (d).

(e) The Agency shall not issue a permit or permit modification for the underground injection of carbon dioxide unless all costs for which the permittee is liable under subsection (d) of this Section have been paid.

(f) No person shall fail or refuse to pay costs for which the person is liable under subsection (d) of this Section.

Section 97. Inseverability. The provisions of this Act are mutually dependent and inseverable. If any provision is held invalid, then this entire Act, including all new and amendatory provisions, is invalid.

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