SB2169 EnrolledLRB097 07925 ASK 48040 b

1    AN ACT concerning regulation.
 
2    Be it enacted by the People of the State of Illinois,
3represented in the General Assembly:
 
4    Section 5. The Illinois Power Agency Act is amended by
5changing Section 1-10 as follows:
 
6    (20 ILCS 3855/1-10)
7    Sec. 1-10. Definitions.
8    "Agency" means the Illinois Power Agency.
9    "Agency loan agreement" means any agreement pursuant to
10which the Illinois Finance Authority agrees to loan the
11proceeds of revenue bonds issued with respect to a project to
12the Agency upon terms providing for loan repayment installments
13at least sufficient to pay when due all principal of, interest
14and premium, if any, on those revenue bonds, and providing for
15maintenance, insurance, and other matters in respect of the
16project.
17    "Authority" means the Illinois Finance Authority.
18    "Clean coal facility" means an electric generating
19facility that uses primarily coal as a feedstock and that
20captures and sequesters carbon dioxide emissions at the
21following levels: at least 50% of the total carbon dioxide
22emissions that the facility would otherwise emit if, at the
23time construction commences, the facility is scheduled to

 

 

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1commence operation before 2016, at least 70% of the total
2carbon dioxide emissions that the facility would otherwise emit
3if, at the time construction commences, the facility is
4scheduled to commence operation during 2016 or 2017, and at
5least 90% of the total carbon dioxide emissions that the
6facility would otherwise emit if, at the time construction
7commences, the facility is scheduled to commence operation
8after 2017. The power block of the clean coal facility shall
9not exceed allowable emission rates for sulfur dioxide,
10nitrogen oxides, carbon monoxide, particulates and mercury for
11a natural gas-fired combined-cycle facility the same size as
12and in the same location as the clean coal facility at the time
13the clean coal facility obtains an approved air permit. All
14coal used by a clean coal facility shall have high volatile
15bituminous rank and greater than 1.7 pounds of sulfur per
16million btu content, unless the clean coal facility does not
17use gasification technology and was operating as a conventional
18coal-fired electric generating facility on June 1, 2009 (the
19effective date of Public Act 95-1027).
20    "Clean coal SNG facility" means a facility that uses a
21gasification process to produce substitute natural gas, that
22sequesters at least 90% of the total carbon emissions that the
23facility would otherwise emit, and that uses at least 90%
24petroleum coke or coal as a feedstock, with all such coal
25having a high bituminous rank and greater than 1.7 pounds of
26sulfur per million btu content, and that has a valid and

 

 

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1effective permit to construct emission sources and air
2pollution control equipment and approval with respect to the
3federal regulations for Prevention of Significant
4Deterioration of Air Quality (PSD) for the plant pursuant to
5the federal Clean Air Act.
6    "Commission" means the Illinois Commerce Commission.
7    "Costs incurred in connection with the development and
8construction of a facility" means:
9        (1) the cost of acquisition of all real property,
10    fixtures, and improvements in connection therewith and
11    equipment, personal property, and other property, rights,
12    and easements acquired that are deemed necessary for the
13    operation and maintenance of the facility;
14        (2) financing costs with respect to bonds, notes, and
15    other evidences of indebtedness of the Agency;
16        (3) all origination, commitment, utilization,
17    facility, placement, underwriting, syndication, credit
18    enhancement, and rating agency fees;
19        (4) engineering, design, procurement, consulting,
20    legal, accounting, title insurance, survey, appraisal,
21    escrow, trustee, collateral agency, interest rate hedging,
22    interest rate swap, capitalized interest, contingency, as
23    required by lenders, and other financing costs, and other
24    expenses for professional services; and
25        (5) the costs of plans, specifications, site study and
26    investigation, installation, surveys, other Agency costs

 

 

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1    and estimates of costs, and other expenses necessary or
2    incidental to determining the feasibility of any project,
3    together with such other expenses as may be necessary or
4    incidental to the financing, insuring, acquisition, and
5    construction of a specific project and starting up,
6    commissioning, and placing that project in operation.
7    "Department" means the Department of Commerce and Economic
8Opportunity.
9    "Director" means the Director of the Illinois Power Agency.
10    "Demand-response" means measures that decrease peak
11electricity demand or shift demand from peak to off-peak
12periods.
13    "Energy efficiency" means measures that reduce the amount
14of electricity or natural gas required to achieve a given end
15use.
16    "Electric utility" has the same definition as found in
17Section 16-102 of the Public Utilities Act.
18    "Facility" means an electric generating unit or a
19co-generating unit that produces electricity along with
20related equipment necessary to connect the facility to an
21electric transmission or distribution system.
22    "Governmental aggregator" means one or more units of local
23government that individually or collectively procure
24electricity to serve residential retail electrical loads
25located within its or their jurisdiction.
26    "Local government" means a unit of local government as

 

 

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1defined in Article VII of Section 1 of the Illinois
2Constitution.
3    "Municipality" means a city, village, or incorporated
4town.
5    "Person" means any natural person, firm, partnership,
6corporation, either domestic or foreign, company, association,
7limited liability company, joint stock company, or association
8and includes any trustee, receiver, assignee, or personal
9representative thereof.
10    "Project" means the planning, bidding, and construction of
11a facility.
12    "Public utility" has the same definition as found in
13Section 3-105 of the Public Utilities Act.
14    "Real property" means any interest in land together with
15all structures, fixtures, and improvements thereon, including
16lands under water and riparian rights, any easements,
17covenants, licenses, leases, rights-of-way, uses, and other
18interests, together with any liens, judgments, mortgages, or
19other claims or security interests related to real property.
20    "Renewable energy credit" means a tradable credit that
21represents the environmental attributes of a certain amount of
22energy produced from a renewable energy resource.
23    "Renewable energy resources" includes energy and its
24associated renewable energy credit or renewable energy credits
25from wind, solar thermal energy, photovoltaic cells and panels,
26biodiesel, crops and untreated and unadulterated organic waste

 

 

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1biomass, tree waste, hydropower that does not involve new
2construction or significant expansion of hydropower dams, and
3other alternative sources of environmentally preferable
4energy. For purposes of this Act, landfill gas produced in the
5State is considered a renewable energy resource. "Renewable
6energy resources" does not include the incineration or burning
7of tires, garbage, general household, institutional, and
8commercial waste, industrial lunchroom or office waste,
9landscape waste other than tree waste, railroad crossties,
10utility poles, or construction or demolition debris, other than
11untreated and unadulterated waste wood.
12    "Revenue bond" means any bond, note, or other evidence of
13indebtedness issued by the Authority, the principal and
14interest of which is payable solely from revenues or income
15derived from any project or activity of the Agency.
16    "Sequester" means permanent storage of carbon dioxide by
17injecting it into a saline aquifer, a depleted gas reservoir,
18or an oil reservoir, directly or through an enhanced oil
19recovery process that may involve intermediate storage,
20regardless of whether these activities are conducted by a clean
21coal facility, a clean coal SNG facility, or a party with which
22a clean coal facility or clean coal SNG facility has contracted
23for such purposes in a salt dome.
24    "Servicing agreement" means (i) in the case of an electric
25utility, an agreement between the owner of a clean coal
26facility and such electric utility, which agreement shall have

 

 

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1terms and conditions meeting the requirements of paragraph (3)
2of subsection (d) of Section 1-75, and (ii) in the case of an
3alternative retail electric supplier, an agreement between the
4owner of a clean coal facility and such alternative retail
5electric supplier, which agreement shall have terms and
6conditions meeting the requirements of Section 16-115(d)(5) of
7the Public Utilities Act.
8    "Substitute natural gas" or "SNG" means a gas manufactured
9by gasification of hydrocarbon feedstock, which is
10substantially interchangeable in use and distribution with
11conventional natural gas.
12    "Total resource cost test" or "TRC test" means a standard
13that is met if, for an investment in energy efficiency or
14demand-response measures, the benefit-cost ratio is greater
15than one. The benefit-cost ratio is the ratio of the net
16present value of the total benefits of the program to the net
17present value of the total costs as calculated over the
18lifetime of the measures. A total resource cost test compares
19the sum of avoided electric utility costs, representing the
20benefits that accrue to the system and the participant in the
21delivery of those efficiency measures, as well as other
22quantifiable societal benefits, including avoided natural gas
23utility costs, to the sum of all incremental costs of end-use
24measures that are implemented due to the program (including
25both utility and participant contributions), plus costs to
26administer, deliver, and evaluate each demand-side program, to

 

 

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1quantify the net savings obtained by substituting the
2demand-side program for supply resources. In calculating
3avoided costs of power and energy that an electric utility
4would otherwise have had to acquire, reasonable estimates shall
5be included of financial costs likely to be imposed by future
6regulations and legislation on emissions of greenhouse gases.
7(Source: P.A. 95-481, eff. 8-28-07; 95-913, eff. 1-1-09;
895-1027, eff. 6-1-09; 96-33, eff. 7-10-09; 96-159, eff.
98-10-09; 96-784, eff. 8-28-09; 96-1000, eff. 7-2-10.)
 
10    Section 10. The Illinois Procurement Code is amended by
11changing Section 1-10 as follows:
 
12    (30 ILCS 500/1-10)
13    Sec. 1-10. Application.
14    (a) This Code applies only to procurements for which
15contractors were first solicited on or after July 1, 1998. This
16Code shall not be construed to affect or impair any contract,
17or any provision of a contract, entered into based on a
18solicitation prior to the implementation date of this Code as
19described in Article 99, including but not limited to any
20covenant entered into with respect to any revenue bonds or
21similar instruments. All procurements for which contracts are
22solicited between the effective date of Articles 50 and 99 and
23July 1, 1998 shall be substantially in accordance with this
24Code and its intent.

 

 

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1    (b) This Code shall apply regardless of the source of the
2funds with which the contracts are paid, including federal
3assistance moneys. This Code shall not apply to:
4        (1) Contracts between the State and its political
5    subdivisions or other governments, or between State
6    governmental bodies except as specifically provided in
7    this Code.
8        (2) Grants, except for the filing requirements of
9    Section 20-80.
10        (3) Purchase of care.
11        (4) Hiring of an individual as employee and not as an
12    independent contractor, whether pursuant to an employment
13    code or policy or by contract directly with that
14    individual.
15        (5) Collective bargaining contracts.
16        (6) Purchase of real estate, except that notice of this
17    type of contract with a value of more than $25,000 must be
18    published in the Procurement Bulletin within 7 days after
19    the deed is recorded in the county of jurisdiction. The
20    notice shall identify the real estate purchased, the names
21    of all parties to the contract, the value of the contract,
22    and the effective date of the contract.
23        (7) Contracts necessary to prepare for anticipated
24    litigation, enforcement actions, or investigations,
25    provided that the chief legal counsel to the Governor shall
26    give his or her prior approval when the procuring agency is

 

 

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1    one subject to the jurisdiction of the Governor, and
2    provided that the chief legal counsel of any other
3    procuring entity subject to this Code shall give his or her
4    prior approval when the procuring entity is not one subject
5    to the jurisdiction of the Governor.
6        (8) Contracts for services to Northern Illinois
7    University by a person, acting as an independent
8    contractor, who is qualified by education, experience, and
9    technical ability and is selected by negotiation for the
10    purpose of providing non-credit educational service
11    activities or products by means of specialized programs
12    offered by the university.
13        (9) Procurement expenditures by the Illinois
14    Conservation Foundation when only private funds are used.
15        (10) Procurement expenditures by the Illinois Health
16    Information Exchange Authority involving private funds
17    from the Health Information Exchange Fund. "Private funds"
18    means gifts, donations, and private grants.
19    (c) This Code does not apply to the electric power
20procurement process provided for under Section 1-75 of the
21Illinois Power Agency Act and Section 16-111.5 of the Public
22Utilities Act.
23    (d) Except for Section 20-160 and Article 50 of this Code,
24and as expressly required by Section 9.1 of the Illinois
25Lottery Law, the provisions of this Code do not apply to the
26procurement process provided for under Section 9.1 of the

 

 

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1Illinois Lottery Law.
2    (e) This Code does not apply to the processes used by the
3Illinois Power Agency to retain a mediator to mediate contract
4disputes between gas utilities and the clean coal SNG facility
5and to retain an expert to assist in the review of contracts
6under subsection (h) of Section 9-220 of the Public Utilities
7Act. This Code does not apply to the process used by the
8Illinois Commerce Commission to retain an expert to assist in
9determining the actual incurred costs of the clean coal SNG
10facility and the reasonableness of those costs as required
11under subsection (h) of Section 9-220 of the Public Utilities
12Act.
13(Source: P.A. 95-481, eff. 8-28-07; 95-615, eff. 9-11-07;
1495-876, eff. 8-21-08; 96-840, eff. 12-23-09; 96-1331, eff.
157-27-10.)
 
16    Section 15. The Public Utilities Act is amended by changing
17Sections 3-101 and 9-220 and by adding Sections 3-123, 3-124,
183-125, and 3-126 as follows:
 
19    (220 ILCS 5/3-101)  (from Ch. 111 2/3, par. 3-101)
20    Sec. 3-101. Definitions. Unless otherwise specified, the
21terms set forth in Sections 3-102 through 3-126 3-121 are used
22in this Act as therein defined.
23(Source: P.A. 84-617; 84-1118.)
 

 

 

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1    (220 ILCS 5/3-123 new)
2    Sec. 3-123. Clean coal facility; clean coal SNG facility;
3sequester; SNG facility; substitute natural gas or SNG. As used
4in this Act:
5    "Clean coal facility" shall have the same meaning as
6provided in Section 1-10 of the Illinois Power Agency Act.
7    "Clean coal SNG facility" shall have the same meaning as
8provided in Section 1-10 of the Illinois Power Agency Act.
9    "Sequester" shall have the same meaning as provided in
10Section 1-10 of the Illinois Power Agency Act.
11    "SNG facility" means a facility that produces substitute
12natural gas from feedstock that includes coal through a
13gasification process, including a clean coal facility, and the
14clean coal SNG facility.
15    "Substitute natural gas" or "SNG" shall have the same
16meaning as provided in Section 1-10 of the Illinois Power
17Agency Act.
 
18    (220 ILCS 5/3-124 new)
19    Sec. 3-124. Adjusted final capitalized plant cost.
20"Adjusted final capitalized plant cost" means the final
21capitalized plant cost reduced by the following, without
22duplication and to the extent not already accounted for or
23reflected on the books of the facility: (1) any State of
24Illinois financial assistance, (2) any U.S. financial
25assistance, and (3) any quantifiable benefit from a U.S. Clean

 

 

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1Coal Gasification Program received by the facility during a
2period equal to the shorter of (A) the life of such program or
3(B) the term of the agreement, such quantifiable benefit to be
4discounted at a rate of 14% per annum over such period.
 
5    (220 ILCS 5/3-125 new)
6    Sec. 3-125. Final capitalized plant cost. "Final
7capitalized plant cost" means the total capitalized asset cost
8of the plant of the clean coal SNG facility as reflected on the
9balance sheet of the facility at the time of the commercial
10production date, with such capitalized cost to be accrued in
11accordance with generally accepted accounting principles, and
12includes, without limitation, the following items: major
13equipment, the SNG pipeline from the plant to the receiving
14pipeline, water lines, railroad improvements, access road
15improvements, all coal transportation assets, including the
16slurry line, slurry prep plant, carbon dioxide capture metering
17and compression, licensing fees, all costs incurred in the
18management planning, oversight and execution of the
19construction and start-up of the plant, and all fees and costs
20payable under engineering, procurement, and design contracts
21for the construct of the plant accrued as of the time of the
22commercial production date, but does not include capitalized
23financing costs including capitalized interest during
24construction and all fees associated with financing, coal
25reserve leasing costs, marketing, training, any and all costs

 

 

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1payable under the contract miner agreement, the cost of coal
2mining equipment and similar costs, and any other costs,
3including general and administrative costs, not reasonably
4incurred in connection with the design, construction, testing,
5start-up, or commissioning of the plant in preparation for
6commercial production date.
 
7    (220 ILCS 5/3-126 new)
8    Sec. 3-126. Total capitalized asset cost. "Total
9capitalized asset cost" means the gross book value of the
10plant, as determined in accordance with generally accepted
11accounting principles at the commercial production date.
 
12    (220 ILCS 5/9-220)  (from Ch. 111 2/3, par. 9-220)
13    Sec. 9-220. Rate changes based on changes in fuel costs.
14    (a) Notwithstanding the provisions of Section 9-201, the
15Commission may authorize the increase or decrease of rates and
16charges based upon changes in the cost of fuel used in the
17generation or production of electric power, changes in the cost
18of purchased power, or changes in the cost of purchased gas
19through the application of fuel adjustment clauses or purchased
20gas adjustment clauses. The Commission may also authorize the
21increase or decrease of rates and charges based upon
22expenditures or revenues resulting from the purchase or sale of
23emission allowances created under the federal Clean Air Act
24Amendments of 1990, through such fuel adjustment clauses, as a

 

 

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1cost of fuel. For the purposes of this paragraph, cost of fuel
2used in the generation or production of electric power shall
3include the amount of any fees paid by the utility for the
4implementation and operation of a process for the
5desulfurization of the flue gas when burning high sulfur coal
6at any location within the State of Illinois irrespective of
7the attainment status designation of such location; but shall
8not include transportation costs of coal (i) except to the
9extent that for contracts entered into on and after the
10effective date of this amendatory Act of 1997, the cost of the
11coal, including transportation costs, constitutes the lowest
12cost for adequate and reliable fuel supply reasonably available
13to the public utility in comparison to the cost, including
14transportation costs, of other adequate and reliable sources of
15fuel supply reasonably available to the public utility, or (ii)
16except as otherwise provided in the next 3 sentences of this
17paragraph. Such costs of fuel shall, when requested by a
18utility or at the conclusion of the utility's next general
19electric rate proceeding, whichever shall first occur, include
20transportation costs of coal purchased under existing coal
21purchase contracts. For purposes of this paragraph "existing
22coal purchase contracts" means contracts for the purchase of
23coal in effect on the effective date of this amendatory Act of
241991, as such contracts may thereafter be amended, but only to
25the extent that any such amendment does not increase the
26aggregate quantity of coal to be purchased under such contract.

 

 

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1Nothing herein shall authorize an electric utility to recover
2through its fuel adjustment clause any amounts of
3transportation costs of coal that were included in the revenue
4requirement used to set base rates in its most recent general
5rate proceeding. Cost shall be based upon uniformly applied
6accounting principles. Annually, the Commission shall initiate
7public hearings to determine whether the clauses reflect actual
8costs of fuel, gas, power, or coal transportation purchased to
9determine whether such purchases were prudent, and to reconcile
10any amounts collected with the actual costs of fuel, power,
11gas, or coal transportation prudently purchased. In each such
12proceeding, the burden of proof shall be upon the utility to
13establish the prudence of its cost of fuel, power, gas, or coal
14transportation purchases and costs. The Commission shall issue
15its final order in each such annual proceeding for an electric
16utility by December 31 of the year immediately following the
17year to which the proceeding pertains, provided, that the
18Commission shall issue its final order with respect to such
19annual proceeding for the years 1996 and earlier by December
2031, 1998.
21    (b) A public utility providing electric service, other than
22a public utility described in subsections (e) or (f) of this
23Section, may at any time during the mandatory transition period
24file with the Commission proposed tariff sheets that eliminate
25the public utility's fuel adjustment clause and adjust the
26public utility's base rate tariffs by the amount necessary for

 

 

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1the base fuel component of the base rates to recover the public
2utility's average fuel and power supply costs per kilowatt-hour
3for the 2 most recent years for which the Commission has issued
4final orders in annual proceedings pursuant to subsection (a),
5where the average fuel and power supply costs per kilowatt-hour
6shall be calculated as the sum of the public utility's prudent
7and allowable fuel and power supply costs as found by the
8Commission in the 2 proceedings divided by the public utility's
9actual jurisdictional kilowatt-hour sales for those 2 years.
10Notwithstanding any contrary or inconsistent provisions in
11Section 9-201 of this Act, in subsection (a) of this Section or
12in any rules or regulations promulgated by the Commission
13pursuant to subsection (g) of this Section, the Commission
14shall review and shall by order approve, or approve as
15modified, the proposed tariff sheets within 60 days after the
16date of the public utility's filing. The Commission may modify
17the public utility's proposed tariff sheets only to the extent
18the Commission finds necessary to achieve conformance to the
19requirements of this subsection (b). During the 5 years
20following the date of the Commission's order, but in any event
21no earlier than January 1, 2007, a public utility whose fuel
22adjustment clause has been eliminated pursuant to this
23subsection shall not file proposed tariff sheets seeking, or
24otherwise petition the Commission for, reinstatement of a fuel
25adjustment clause.
26    (c) Notwithstanding any contrary or inconsistent

 

 

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1provisions in Section 9-201 of this Act, in subsection (a) of
2this Section or in any rules or regulations promulgated by the
3Commission pursuant to subsection (g) of this Section, a public
4utility providing electric service, other than a public utility
5described in subsection (e) or (f) of this Section, may at any
6time during the mandatory transition period file with the
7Commission proposed tariff sheets that establish the rate per
8kilowatt-hour to be applied pursuant to the public utility's
9fuel adjustment clause at the average value for such rate
10during the preceding 24 months, provided that such average rate
11results in a credit to customers' bills, without making any
12revisions to the public utility's base rate tariffs. The
13proposed tariff sheets shall establish the fuel adjustment rate
14for a specific time period of at least 3 years but not more
15than 5 years, provided that the terms and conditions for any
16reinstatement earlier than 5 years shall be set forth in the
17proposed tariff sheets and subject to modification or approval
18by the Commission. The Commission shall review and shall by
19order approve the proposed tariff sheets if it finds that the
20requirements of this subsection are met. The Commission shall
21not conduct the annual hearings specified in the last 3
22sentences of subsection (a) of this Section for the utility for
23the period that the factor established pursuant to this
24subsection is in effect.
25    (d) A public utility providing electric service, or a
26public utility providing gas service may file with the

 

 

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1Commission proposed tariff sheets that eliminate the public
2utility's fuel or purchased gas adjustment clause and adjust
3the public utility's base rate tariffs to provide for recovery
4of power supply costs or gas supply costs that would have been
5recovered through such clause; provided, that the provisions of
6this subsection (d) shall not be available to a public utility
7described in subsections (e) or (f) of this Section to
8eliminate its fuel adjustment clause. Notwithstanding any
9contrary or inconsistent provisions in Section 9-201 of this
10Act, in subsection (a) of this Section, or in any rules or
11regulations promulgated by the Commission pursuant to
12subsection (g) of this Section, the Commission shall review and
13shall by order approve, or approve as modified in the
14Commission's order, the proposed tariff sheets within 240 days
15after the date of the public utility's filing. The Commission's
16order shall approve rates and charges that the Commission,
17based on information in the public utility's filing or on the
18record if a hearing is held by the Commission, finds will
19recover the reasonable, prudent and necessary jurisdictional
20power supply costs or gas supply costs incurred or to be
21incurred by the public utility during a 12 month period found
22by the Commission to be appropriate for these purposes,
23provided, that such period shall be either (i) a 12 month
24historical period occurring during the 15 months ending on the
25date of the public utility's filing, or (ii) a 12 month future
26period ending no later than 15 months following the date of the

 

 

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1public utility's filing. The public utility shall include with
2its tariff filing information showing both (1) its actual
3jurisdictional power supply costs or gas supply costs for a 12
4month historical period conforming to (i) above and (2) its
5projected jurisdictional power supply costs or gas supply costs
6for a future 12 month period conforming to (ii) above. If the
7Commission's order requires modifications in the tariff sheets
8filed by the public utility, the public utility shall have 7
9days following the date of the order to notify the Commission
10whether the public utility will implement the modified tariffs
11or elect to continue its fuel or purchased gas adjustment
12clause in force as though no order had been entered. The
13Commission's order shall provide for any reconciliation of
14power supply costs or gas supply costs, as the case may be, and
15associated revenues through the date that the public utility's
16fuel or purchased gas adjustment clause is eliminated. During
17the 5 years following the date of the Commission's order, a
18public utility whose fuel or purchased gas adjustment clause
19has been eliminated pursuant to this subsection shall not file
20proposed tariff sheets seeking, or otherwise petition the
21Commission for, reinstatement or adoption of a fuel or
22purchased gas adjustment clause. Nothing in this subsection (d)
23shall be construed as limiting the Commission's authority to
24eliminate a public utility's fuel adjustment clause or
25purchased gas adjustment clause in accordance with any other
26applicable provisions of this Act.

 

 

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1    (e) Notwithstanding any contrary or inconsistent
2provisions in Section 9-201 of this Act, in subsection (a) of
3this Section, or in any rules promulgated by the Commission
4pursuant to subsection (g) of this Section, a public utility
5providing electric service to more than 1,000,000 customers in
6this State may, within the first 6 months after the effective
7date of this amendatory Act of 1997, file with the Commission
8proposed tariff sheets that eliminate, effective January 1,
91997, the public utility's fuel adjustment clause without
10adjusting its base rates, and such tariff sheets shall be
11effective upon filing. To the extent the application of the
12fuel adjustment clause had resulted in net charges to customers
13after January 1, 1997, the utility shall also file a tariff
14sheet that provides for a refund stated on a per kilowatt-hour
15basis of such charges over a period not to exceed 6 months;
16provided however, that such refund shall not include the
17proportional amounts of taxes paid under the Use Tax Act,
18Service Use Tax Act, Service Occupation Tax Act, and Retailers'
19Occupation Tax Act on fuel used in generation. The Commission
20shall issue an order within 45 days after the date of the
21public utility's filing approving or approving as modified such
22tariff sheet. If the fuel adjustment clause is eliminated
23pursuant to this subsection, the Commission shall not conduct
24the annual hearings specified in the last 3 sentences of
25subsection (a) of this Section for the utility for any period
26after December 31, 1996 and prior to any reinstatement of such

 

 

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1clause. A public utility whose fuel adjustment clause has been
2eliminated pursuant to this subsection shall not file a
3proposed tariff sheet seeking, or otherwise petition the
4Commission for, reinstatement of the fuel adjustment clause
5prior to January 1, 2007.
6    (f) Notwithstanding any contrary or inconsistent
7provisions in Section 9-201 of this Act, in subsection (a) of
8this Section, or in any rules or regulations promulgated by the
9Commission pursuant to subsection (g) of this Section, a public
10utility providing electric service to more than 500,000
11customers but fewer than 1,000,000 customers in this State may,
12within the first 6 months after the effective date of this
13amendatory Act of 1997, file with the Commission proposed
14tariff sheets that eliminate, effective January 1, 1997, the
15public utility's fuel adjustment clause and adjust its base
16rates by the amount necessary for the base fuel component of
17the base rates to recover 91% of the public utility's average
18fuel and power supply costs for the 2 most recent years for
19which the Commission, as of January 1, 1997, has issued final
20orders in annual proceedings pursuant to subsection (a), where
21the average fuel and power supply costs per kilowatt-hour shall
22be calculated as the sum of the public utility's prudent and
23allowable fuel and power supply costs as found by the
24Commission in the 2 proceedings divided by the public utility's
25actual jurisdictional kilowatt-hour sales for those 2 years,
26provided, that such tariff sheets shall be effective upon

 

 

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1filing. To the extent the application of the fuel adjustment
2clause had resulted in net charges to customers after January
31, 1997, the utility shall also file a tariff sheet that
4provides for a refund stated on a per kilowatt-hour basis of
5such charges over a period not to exceed 6 months. Provided
6however, that such refund shall not include the proportional
7amounts of taxes paid under the Use Tax Act, Service Use Tax
8Act, Service Occupation Tax Act, and Retailers' Occupation Tax
9Act on fuel used in generation. The Commission shall issue an
10order within 45 days after the date of the public utility's
11filing approving or approving as modified such tariff sheet. If
12the fuel adjustment clause is eliminated pursuant to this
13subsection, the Commission shall not conduct the annual
14hearings specified in the last 3 sentences of subsection (a) of
15this Section for the utility for any period after December 31,
161996 and prior to any reinstatement of such clause. A public
17utility whose fuel adjustment clause has been eliminated
18pursuant to this subsection shall not file a proposed tariff
19sheet seeking, or otherwise petition the Commission for,
20reinstatement of the fuel adjustment clause prior to January 1,
212007.
22    (g) The Commission shall have authority to promulgate rules
23and regulations to carry out the provisions of this Section.
24    (h) Any Illinois gas utility may enter into a contract on
25or before September 30 March 31, 2011 for up to 10 years of
26supply with any company for the purchase of substitute natural

 

 

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1gas (SNG) produced from coal through the gasification process
2if the company has commenced construction of a clean coal SNG
3gasification facility by July 1, 2012 in Jefferson County and
4commencement of construction shall mean that material physical
5site work has occurred, such as site clearing and excavation,
6water runoff prevention, water retention reservoir
7preparation, or foundation development. The contract shall
8contain the following provisions: (i) at least 90% of feedstock
9the only coal to be used in the gasification process shall be
10coal with a has high volatile bituminous rank and greater than
111.7 pounds of sulfur per million Btu content; (ii) at the time
12the contract term commences, the price per million Btu may not
13exceed $7.95 in 2008 dollars, adjusted annually based on the
14change in the Annual Consumer Price Index for All Urban
15Consumers for the Midwest Region as published in April by the
16United States Department of Labor, Bureau of Labor Statistics
17(or a suitable Consumer Price Index calculation if this
18Consumer Price Index is not available) for the previous
19calendar year; provided that the price per million Btu shall
20not exceed $9.95 at any time during the contract; (iii) the
21utility's aggregate long-term supply contract contracts for
22the purchase of SNG does not exceed 15% 25% of the annual
23system supply requirements of the utility as of 2008 and the
24quantity of SNG supplied to a utility may not exceed 16 million
25MMBtus; and (iv) the contract costs pursuant to subsection
26(h-10) of this Section shall not include any lobbying expenses,

 

 

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1charitable contributions, advertising, organizational
2memberships, carbon dioxide pipeline or sequestration
3expenses, or marketing expenses per year.
4    Any gas utility that is providing service to more than
5150,000 customers on the effective date of this amendatory Act
6of the 97th General Assembly shall either elect to enter into a
7contract on or before September 30, 2011 for 10 years of SNG
8supply with the owner of a clean coal SNG facility or to file
9biennial rate proceedings before the Commission in the years
102012, 2014, and 2016, with such filings made after the
11effective date of this amendatory Act of the 97th General
12Assembly and no later than September 30 of the years 2012,
132014, and 2016 consistent with all requirements of 83 Ill. Adm.
14Code 255 and 285 as though the gas utility were filing for an
15increase in its rates, without regard to whether such filing
16would produce an increase, a decrease, or no change in the gas
17utility's rates, and the Commission shall review the gas
18utility's filing and shall issue its order in accordance with
19the provisions of Section 9-201 of this Act.
20    Within 7 days after the effective date of this amendatory
21Act of the 97th General Assembly, the owner of the clean coal
22SNG facility shall submit to the Illinois Power Agency and each
23gas utility that is providing service to more than 150,000
24customers on the effective date of this amendatory Act of the
2597th General Assembly a copy of a draft contract. Within 30
26days after the receipt of the draft contract, each such gas

 

 

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1utility shall provide the Illinois Power Agency and the owner
2of the clean coal SNG facility with its comments and
3recommended revisions to the draft contract. Within 7 days
4after the receipt of the gas utility's comments and recommended
5revisions, the owner of the facility shall submit its
6responsive comments and a further revised draft of the contract
7to the Illinois Power Agency. The Illinois Power Agency shall
8review the draft contract and comments.
9    During its review of the draft contract, the Illinois Power
10Agency shall:
11        (1) review and confirm in writing that the terms stated
12    in this subsection (h) are incorporated in the SNG
13    contract;
14        (2) review the SNG pricing formula included in the
15    contract and approve that formula if the Illinois Power
16    Agency determines that the formula, at the time the
17    contract term commences: (A) starts with a price of $6.50
18    per MMBtu adjusted by the adjusted final capitalized plant
19    cost; (B) takes into account budgeted miscellaneous net
20    revenue after cost allowance, including sale of SNG
21    produced by the clean coal SNG facility above the nameplate
22    capacity of the facility and other by-products produced by
23    the facility, as approved by the Illinois Power Agency; (C)
24    does not include carbon dioxide transportation or
25    sequestration expenses; and (D) includes all provisions
26    required under this subsection (h); if the Illinois Power

 

 

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1    Agency does not approve of the SNG pricing formula, then
2    the Illinois Power Agency shall modify the formula to
3    ensure that it meets the requirements of this subsection
4    (h);
5        (3) review and approve the amount of budgeted
6    miscellaneous net revenue after cost allowance, including
7    sale of SNG produced by the clean coal SNG facility above
8    the nameplate capacity of the facility and other
9    by-products produced by the facility, to be included in the
10    pricing formula; the Illinois Power Agency shall approve
11    the amount of budgeted miscellaneous net revenue to be
12    included in the pricing formula if it determines the
13    budgeted amount to be reasonable and accurate;
14        (4) review and confirm in writing that using the EIA
15    Annual Energy Outlook-2011 Henry Hub Spot Price, the
16    contract terms set out in subsection (h), the
17    reconciliation account terms as set out in subsection
18    (h-15), and an estimated inflation rate of 2.5% for each
19    corresponding year, that there will be no cumulative
20    estimated increase for residential customers; and
21        (5) allocate the nameplate capacity of the clean coal
22    SNG by total therms sold to ultimate customers by each gas
23    utility in 2008; provided, however, no utility shall be
24    required to purchase more than 42% of the projected annual
25    output of the facility; additionally, the Illinois Power
26    Agency shall further adjust the allocation only as required

 

 

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1    to take into account (A) adverse consolidation,
2    derivative, or lease impacts to the balance sheet or income
3    statement of any gas utility or (B) the physical capacity
4    of the gas utility to accept SNG.
5    If the parties to the contract do not agree on the terms
6therein, then the Illinois Power Agency shall retain an
7independent mediator to mediate the dispute between the
8parties. If the parties are in agreement on the terms of the
9contract, then the Illinois Power Agency shall approve the
10contract. If after mediation the parties have failed to come to
11agreement, then the Illinois Power Agency shall revise the
12draft contract as necessary to confirm that the contract
13contains only terms that are reasonable and equitable. The
14Illinois Power Agency may, in its discretion, retain an
15independent, qualified, and experienced expert to assist in its
16obligations under this subsection (h). The Illinois Power
17Agency shall adopt and make public policies detailing the
18processes for retaining a mediator and an expert under this
19subsection (h). Any mediator or expert retained under this
20subsection (h) shall be retained no later than 60 days after
21the effective date of this amendatory Act of the 97th General
22Assembly.
23    The Illinois Power Agency shall complete all of its
24responsibilities under this subsection (h) within 60 days after
25the effective date of this amendatory Act of the 97th General
26Assembly. The clean coal SNG facility shall pay a reasonable

 

 

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1fee as required by the Illinois Power Agency for its services
2under this subsection (h) and shall pay the mediator's and
3expert's reasonable fees, if any. A gas utility and its
4customers shall have no obligation to reimburse the clean coal
5SNG facility or the Illinois Power Agency of any such costs.
6    Within 30 days after commercial production of SNG has
7begun, the Commission shall initiate a review to determine
8whether the final capitalized plant cost of the clean coal SNG
9facility reflects actual incurred costs and whether the
10incurred costs were reasonable. In determining the actual
11incurred costs included in the final capitalized plant cost and
12the reasonableness of those costs, the Commission may in its
13discretion retain independent, qualified, and experienced
14experts to assist in its determination. The expert shall not
15own or control any direct or indirect interest in the clean
16coal SNG facility and shall have no contractual relationship
17with the clean coal SNG facility. If an expert is retained by
18the Commission, then the clean coal SNG facility shall pay the
19expert's reasonable fees. The fees shall not be passed on to a
20utility or its customers. The Commission shall adopt and make
21public a policy detailing the process for retaining experts
22under this subsection (h).
23    Within 30 days after completion of its review, the
24Commission shall initiate a formal proceeding on the final
25capitalized plant cost of the clean coal SNG facility at which
26comments and testimony may be submitted by any interested

 

 

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1parties and the public. If the Commission finds that the final
2capitalized plant cost includes costs that were not actually
3incurred or costs that were unreasonably incurred, then the
4Commission shall disallow the amount of non-incurred or
5unreasonable costs from the SNG price under contracts entered
6into under this subsection (h). If the Commission disallows any
7costs, then the Commission shall adjust the SNG price using the
8price formula in the contract approved by the Illinois Power
9Agency under this subsection (h) to reflect the disallowed
10costs and shall enter an order specifying the revised price. In
11addition, the Commission's order shall direct the clean coal
12SNG facility to issue refunds of such sums as shall represent
13the difference between actual gross revenues and the gross
14revenue that would have been obtained based upon the same
15volume, from the price revised by the Commission. Any refund
16shall include interest calculated at a rate determined by the
17Commission and shall be returned according to procedures
18prescribed by the Commission.
19    Nothing in this subsection (h) shall preclude any party
20affected by a decision of the Commission under this subsection
21(h) from seeking judicial review of the Commission's decision.
22    (h-5) All contracts entered into under subsection (h) of
23this Section, regardless of duration, shall require the owner
24of any facility supplying SNG under the contract to provide
25certified documentation to the Commission each year, starting
26in the facility's first year of commercial operation,

 

 

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1accurately reporting the quantity of carbon dioxide emissions
2from the facility that have been captured and sequestered and
3reporting any quantities of carbon dioxide released from the
4site or sites at which carbon dioxide emissions were
5sequestered in prior years, based on continuous monitoring of
6those sites.
7    If, in any year, the owner of the clean coal SNG facility
8fails to demonstrate that the SNG facility captured and
9sequestered at least 90% of the total carbon dioxide emissions
10that the facility would otherwise emit or that sequestration of
11emissions from prior years has failed, resulting in the release
12of carbon dioxide into the atmosphere, then the owner of the
13clean coal SNG facility must pay a penalty of $20 per ton of
14excess carbon dioxide emissions not to exceed $40,000,000, in
15any given year which shall be deposited into the Energy
16Efficiency Trust Fund and distributed pursuant to subsection
17(b) of Section 6-6 of the Renewable Energy, Energy Efficiency,
18and Coal Resources Development Law of 1997. On or before the
195-year anniversary of the execution of the contract and every 5
20years thereafter, an expert hired by the owner of the facility
21with the approval of the Attorney General shall conduct an
22analysis to determine the cost of sequestration of at least 90%
23of the total carbon dioxide emissions the plant would otherwise
24emit. If the analysis shows that the actual annual cost is
25greater than the penalty, then the penalty shall be increased
26to equal the actual cost. Provided, however, to the extent that

 

 

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1the owner of the facility described in subsection (h) of this
2Act can demonstrate that the failure was as a result of acts of
3God (including fire, flood, earthquake, tornado, lightning,
4hurricane, or other natural disaster); any amendment,
5modification, or abrogation of any applicable law or regulation
6that would prevent performance; war; invasion; act of foreign
7enemies; hostilities (regardless of whether war is declared);
8civil war; rebellion; revolution; insurrection; military or
9usurped power or confiscation; terrorist activities; civil
10disturbance; riots; nationalization; sabotage; blockage; or
11embargo, the owner of the facility described in subsection (h)
12of this Act shall not be subject to a penalty if and only if (i)
13it promptly provides notice of its failure to the Commission;
14(ii) as soon as practicable and consistent with any order or
15direction from the Commission, it submits to the Commission
16proposed modifications to its carbon capture and sequestration
17plan; and (iii) it carries out its proposed modifications in
18the manner and time directed by the Commission.
19    If the Commission finds that the facility has not satisfied
20each of these requirements, then the facility shall be subject
21to the penalty. If the owner of the clean coal SNG facility
22captured and sequestered more than 90% of the total carbon
23dioxide emissions that the facility would otherwise emit, then
24the owner of the facility may credit such additional amounts to
25reduce the amount of any future penalty to be paid. The penalty
26resulting from the failure to capture and sequester at least

 

 

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1the minimum amount of carbon dioxide shall not be passed on to
2a utility or its customers.
3    If the clean coal SNG facility fails to meet the
4requirements specified in this subsection (h-5), then the
5Attorney General, on behalf of the People of the State of
6Illinois, shall bring an action to enforce the obligations
7related to the facility set forth in this subsection (h-5),
8including any penalty payments owed, but not including the
9physical obligation to capture and sequester at least 90% of
10the total carbon dioxide emissions that the facility would
11otherwise emit. Such action may be filed in any circuit court
12in Illinois. By entering into a contract pursuant to subsection
13(h) of this Section, the clean coal SNG facility agrees to
14waive any objections to venue or to the jurisdiction of the
15court with regard to the Attorney General's action under this
16subsection (h-5).
17    Compliance with the sequestration requirements and any
18penalty requirements specified in this subsection (h-5) for the
19clean coal SNG facility shall be assessed annually by the
20Commission, which may in its discretion retain an expert to
21facilitate its assessment. If any expert is retained by the
22Commission, then the clean coal SNG facility shall pay for the
23expert's reasonable fees, and such costs shall not be passed
24through to the utility or its customers.
25    In addition, carbon dioxide emission credits received by
26the clean coal SNG facility in connection with sequestration of

 

 

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1carbon dioxide from the facility must be sold in a timely
2fashion with any revenue, less applicable fees and expenses and
3any expenses required to be paid by facility for carbon dioxide
4transportation or sequestration, deposited into the
5reconciliation account within 30 days after receipt of such
6funds by the owner of the clean coal SNG facility.
7    The clean coal SNG facility is prohibited from transporting
8or sequestering carbon dioxide unless the owner of the carbon
9dioxide pipeline that transfers the carbon dioxide from the
10facility and the owner of the sequestration site where the
11carbon dioxide captured by the facility is stored has acquired
12all applicable permits under applicable State and federal laws,
13statutes, rules, or regulations prior to the transfer or
14sequestration of carbon dioxide. The responsibility for
15compliance with the sequestration requirements specified in
16this subsection (h-5) for the clean coal SNG facility shall
17reside solely with the clean coal SNG facility, regardless of
18whether the facility has contracted with another party to
19capture, transport, or sequester carbon dioxide.
20    (h-7) Sequestration permitting, oversight, and
21investigations. No clean coal facility may transport or
22sequester carbon dioxide unless the Commission approves the
23method of carbon dioxide transportation or sequestration. Such
24approval shall be required regardless of whether the facility
25has contracted with another to transport or sequester the
26carbon dioxide. Nothing in this subsection (h-7) shall release

 

 

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1the owner or operator of a carbon dioxide sequestration site or
2carbon dioxide pipeline from any other permitting requirements
3under applicable State and federal laws, statutes, rules, or
4regulations.
5    The Commission shall review carbon dioxide transportation
6and sequestration methods proposed by a clean coal facility and
7shall approve those methods it deems reasonable and
8cost-effective. For purposes of this review, "cost-effective"
9means a commercially reasonable price for similar carbon
10dioxide transportation or sequestration techniques. In
11determining whether sequestration is reasonable and
12cost-effective, the Commission may consult with the Illinois
13State Geological Survey and retain third parties to assist in
14its determination, provided that such third parties shall not
15own or control any direct or indirect interest in the facility
16that is proposing the carbon dioxide transportation or the
17carbon dioxide sequestration method and shall have no
18contractual relationship with that facility. If a third party
19is retained by the Commission, then the facility proposing the
20carbon dioxide transportation or sequestration method shall
21pay for the expert's reasonable fees, and these costs shall not
22be passed through to a utility or its customers.
23    No later than 6 months prior to the date upon which the
24owner intends to commence construction of a clean coal
25facility, the owner of the facility shall file with the
26Commission a carbon dioxide transportation or sequestration

 

 

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1plan. The Commission shall hold a public hearing within 30 days
2after receipt of the facility's carbon dioxide transportation
3or sequestration plan. The Commission shall post notice of the
4review on its website upon submission of a carbon dioxide
5transportation or sequestration method and shall accept
6written public comments. The Commission shall take the comments
7into account when making its decision.
8    The Commission may not approve a carbon dioxide
9sequestration method if the owner or operator of the
10sequestration site has not received (i) an Underground
11Injection Control permit from the Illinois Environmental
12Protection Agency pursuant to the Environmental Protection
13Act; (ii) an Underground Injection Control permit from the
14Illinois Department of Natural Resources pursuant to the
15Illinois Oil and Gas Act; or (iii) a permit similar to items
16(i) or (ii) from the state in which the sequestration site is
17located if the sequestration will take place outside of
18Illinois. The Commission shall approve or deny the carbon
19dioxide transportation or sequestration method within 90 days
20after the receipt of all required information.
21    At least annually, the Illinois Environmental Protection
22Agency shall inspect all carbon dioxide sequestration sites in
23Illinois. The Illinois Environmental Protection Agency may, as
24often as deemed necessary, monitor and conduct investigations
25of those sites. The owner or operator of the sequestration site
26must cooperate with the Illinois Environmental Protection

 

 

SB2169 Enrolled- 37 -LRB097 07925 ASK 48040 b

1Agency investigations of carbon dioxide sequestration sites.
2    If the Illinois Environmental Protection Agency determines
3at any time a site creates conditions that warrant the issuance
4of a seal order under Section 34 of the Environmental
5Protection Act, then the Illinois Environmental Protection
6Agency shall seal the site pursuant to the Environmental
7Protection Act. If the Illinois Environmental Protection
8Agency determines at any time a carbon dioxide sequestration
9site creates conditions that warrant the institution of a civil
10action for an injunction under Section 43 of the Environmental
11Protection Act, then the Illinois Environmental Protection
12Agency shall request the State's Attorney or the Attorney
13General institute such action. The Illinois Environmental
14Protection Agency shall provide notice of any such actions as
15soon as possible on its website. The facility shall incur all
16reasonable costs associated with any such inspection or
17monitoring of the sequestration sites, and these costs shall
18not be recoverable from utilities or their customers.
19    At least annually, the Commission shall inspect all carbon
20dioxide pipelines in Illinois that transport carbon dioxide to
21ensure the safety and feasibility of those pipelines. The
22Commission may, as often as deemed necessary, monitor and
23conduct investigations of those pipelines. The owner or
24operator of the pipeline must cooperate with the Commission
25investigations of the carbon dioxide pipelines.
26    In circumstances whereby a carbon dioxide pipeline creates

 

 

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1a substantial danger to the environment or to the public health
2of persons or to the welfare of persons where such danger is to
3the livelihood of such persons, the State's Attorney or
4Attorney General, upon the request of the Commission or on his
5or her own motion, may institute a civil action for an
6immediate injunction to halt any discharge or other activity
7causing or contributing to the danger or to require such other
8action as may be necessary. The court may issue an ex parte
9order and shall schedule a hearing on the matter not later than
103 working days after the date of injunction. The Commission
11shall provide notice of any such actions as soon as possible on
12its website. The SNG facility shall incur all reasonable costs
13associated with any such inspection or monitoring of the
14sequestration sites, and these costs shall not be recoverable
15from a utility or its customers.
16    (h-5) The Attorney General, on behalf of the people of the
17State of Illinois, may specifically enforce the requirements of
18this subsection (h-5). All contracts, regardless of duration,
19shall require the owner of any facility supplying SNG under the
20contract to provide documentation to the Commission each year,
21starting in the facility's first year of commercial operation,
22accurately reporting the quantity of carbon dioxide emissions
23from the facility that have been captured and sequestered and
24reporting any quantities of carbon dioxide released from the
25site or sites at which carbon dioxide emissions were
26sequestered in prior years, based on continuous monitoring of

 

 

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1those sites. If, in any year, the owner of the facility fails
2to demonstrate that the SNG facility captured and sequestered
3at least 90% of the total carbon dioxide emissions that the
4facility would otherwise emit or that sequestration of
5emissions from prior years has failed, resulting in the release
6of carbon dioxide into the atmosphere, then the owner of the
7facility must offset excess emissions. Any such carbon dioxide
8offsets must be permanent, additional, verifiable, real,
9located within the State of Illinois, and legally and
10practicably enforceable; provided that the owner of the
11facility shall not be obligated to acquire carbon dioxide
12emission offsets to the extent that the cost of acquiring such
13offsets would exceed $40 million in any given year. No costs of
14any purchases of carbon offsets may be recovered from a utility
15or its customers. All carbon offsets purchased for this purpose
16must be permanently retired. In addition, carbon dioxide
17emission credits equivalent to 50% of the amount of credits
18associated with the required sequestration of carbon dioxide
19from the facility must be permanently retired. Compliance with
20the sequestration requirements and the offset purchase
21requirements specified in this subsection (h-5) shall be
22assessed annually by an independent expert retained by the
23owner of the SNG facility, with the advance written approval of
24the Attorney General. A SNG facility operating pursuant to this
25subsection (h-5) shall not forfeit its designation as a clean
26coal SNG facility if the facility fails to fully comply with

 

 

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1the applicable carbon sequestration requirements in any given
2year, provided the requisite offsets are purchased.
3    (h-10) Contract costs for SNG incurred by an Illinois gas
4utility are reasonable and prudent and recoverable through the
5purchased gas adjustment clause and are not subject to review
6or disallowance by the Commission. Contract costs are costs
7incurred by the utility under the terms of a contract that
8incorporates the terms stated in subsection (h) of this Section
9as confirmed in writing by the Illinois Power Agency as set
10forth in subsection (h) (h-20) of this Section, which
11confirmation shall be deemed conclusive, or as a consequence of
12or condition to its performance under the contract, including
13(i) amounts paid for SNG under the SNG contract and (ii) costs
14of transportation and storage services of SNG purchased from
15interstate pipelines under federally approved tariffs. The
16Illinois gas utility shall initiate a clean coal SNG facility
17rider mechanism that (A) shall be applicable to all customers
18who receive transportation service from the utility, (B) shall
19be designed to have an equal percentage impact on the
20transportation services rates of each class of the utility's
21total customers, and (C) shall accurately reflect the net
22customer savings, if any, and above market costs, if any, under
23the SNG contract. Any contract, the terms of which have been
24confirmed in writing by the Illinois Power Agency as set forth
25in subsection (h) (h-20) of this Section and the performance of
26the parties under such contract cannot be grounds for

 

 

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1challenging prudence or cost recovery by the utility through
2the purchased gas adjustment clause, and in such cases, the
3Commission is directed not to consider, and has no authority to
4consider, any attempted challenges.
5    The contracts entered into by Illinois gas utilities
6pursuant to subsection (h) of this Section shall provide that
7the utility retains the right to terminate the contract without
8further obligation or liability to any party if the contract
9has been impaired as a result of any legislative,
10administrative, judicial, or other governmental action that is
11taken that eliminates all or part of the prudence protection of
12this subsection (h-10) or denies the recoverability of all or
13part of the contract costs through the purchased gas adjustment
14clause. Should any Illinois gas utility exercise its right
15under this subsection (h-10) to terminate the contract, all
16contract costs incurred prior to termination are and will be
17deemed reasonable, prudent, and recoverable as and when
18incurred and not subject to review or disallowance by the
19Commission. Any order, issued by the State requiring or
20authorizing the discontinuation of the merchant function,
21defined as the purchase and sale of natural gas by an Illinois
22gas utility for the ultimate consumer in its service territory
23shall include provisions necessary to prevent the impairment of
24the value of any contract hereunder over its full term.
25    (h-15) Reconciliation account. The clean coal SNG facility
26shall establish a reconciliation account for the benefit of the

 

 

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1retail customers of the utilities that have entered into
2contracts with the clean coal SNG facility pursuant to
3subsection (h). The reconciliation account shall be maintained
4and administered by an independent trustee that is mutually
5agreed upon by the owners of the clean coal SNG facility, the
6utilities, and the Commission in an interest-bearing account in
7accordance with the following:
8        (1) The clean coal SNG facility shall conduct an
9    analysis annually within 60 days after receiving the
10    necessary cost information, which shall be provided by the
11    gas utility within 6 months after the end of the preceding
12    calendar year, to determine (i) the average annual contract
13    SNG cost, which shall be calculated as the total amount
14    paid for SNG purchased from the clean coal SNG facility
15    over the preceding 12 months, plus the cost to the utility
16    of the required transportation and storage services of SNG,
17    divided by the total number of MMBtus of SNG actually
18    purchased from the clean coal SNG facility in the preceding
19    12 months under the utility contract; (ii) the average
20    annual natural gas purchase cost, which shall be calculated
21    as the total annual supply costs paid for baseload natural
22    gas (excluding any SNG) purchased by such utility over the
23    preceding 12 months plus the costs of transportation and
24    storage services of such natural gas (excluding such costs
25    for SNG), divided by the total number of MMbtus of baseload
26    natural gas (excluding SNG) actually purchased by the

 

 

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1    utility during the year; (iii) the cost differential, which
2    shall be the difference between the average annual contract
3    SNG cost and the average annual natural gas purchase cost;
4    and (iv) the revenue share target which shall be the cost
5    differential multiplied by the total amount of SNG
6    purchased over the preceding 12 months under such utility
7    contract.
8            (A) To the extent the annual average contract SNG
9        cost is less than the annual average natural gas
10        purchase cost, the utility shall credit an amount equal
11        to the revenue share target to the reconciliation
12        account. Such credit payment shall be made monthly
13        starting within 30 days after the completed analysis in
14        this subsection (h-15) and based on collections from
15        all customers via a line item charge in all customer
16        bills designed to have an equal percentage impact on
17        the transportation services of each class of
18        customers. Credit payments made pursuant to this
19        subparagraph (A) shall be deemed prudent and
20        reasonable and not subject to Commission prudence
21        review.
22            (B) To the extent the annual average contract SNG
23        cost is greater than the annual average natural gas
24        purchase cost, the reconciliation account shall be
25        used to provide a credit equal to the revenue share
26        target to the utilities to be used to reduce the

 

 

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1        utility's natural gas costs through the purchased gas
2        adjustment clause. Such payment shall be made within 30
3        days after the completed analysis pursuant to this
4        subsection (h-15), but only to the extent that the
5        reconciliation account has a positive balance.
6        (2) At the conclusion of the term of the SNG contracts
7    pursuant to subsection (h) and the completion of the final
8    annual analysis pursuant to this subsection (h-15), to the
9    extent the facility owes any amount to retail customers,
10    amounts in the account shall be credited to retail
11    customers to the extent the owed amount is repaid; 50% of
12    any additional amount in the reconciliation account shall
13    be distributed to the utilities to be used to reduce the
14    utilities' natural gas costs through the purchase gas
15    adjustment clause with the remaining amount distributed to
16    the clean coal SNG facility. Such payment shall be made
17    within 30 days after the last completed analysis pursuant
18    to this subsection (h-15). If the facility has repaid all
19    owed amounts, if any, to retail customers and has
20    distributed 50% of any additional amount in the account to
21    the utilities, then the owners of the clean coal SNG
22    facility shall have no further obligation to the utility or
23    the retail customers.
24        If, at the conclusion of the term of the contracts
25    pursuant to subsection (h) and the completion of the final
26    annual analysis pursuant to this subsection (h-15), the

 

 

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1    facility owes any amount to retail customers and the
2    account has been depleted, then the clean coal SNG facility
3    shall be liable for any remaining amount owed to the retail
4    customers. The clean coal SNG facility shall market the
5    daily production of SNG and distribute on a monthly basis
6    5% of the amounts collected with respect to such future
7    sales to the utilities in proportion to each utility's SNG
8    contract to be used to reduce the utility's natural gas
9    costs through the purchase gas adjustment clause; such
10    payments to the utility shall continue until either 15
11    years after the conclusion of the contract or such time as
12    the sum of such payments equals the remaining amount owed
13    to the retail customers at the end of the contract,
14    whichever is earlier. If the debt to the retail customers
15    is not repaid within 15 years after the conclusion of the
16    contract, then the owner of the clean coal SNG facility
17    must sell the facility, and all proceeds from that sale
18    must be used to repay any amount owed to the retail
19    customers under this subsection (h-15).
20        The retail customers shall have first priority in
21    recovering that debt above any creditors, except the
22    secured lenders to the extent that the secured lenders have
23    any secured debt outstanding, including any parent
24    companies or affiliates of the clean coal SNG facility.
25        (3) 50% of all additional net revenue, defined as
26    miscellaneous net revenue after cost allowance and above

 

 

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1    the budgeted estimate established for revenue pursuant to
2    subsection (h), including sale of substitute natural gas
3    derived from the clean coal SNG facility above the
4    nameplate capacity of the facility and other by-products
5    produced by the facility, shall be credited to the
6    reconciliation account on an annual basis with such payment
7    made within 30 days after the end of each calendar year
8    during the term of the contract.
9        (4) The clean coal SNG facility shall each year,
10    starting in the facility's first year of commercial
11    operation, file with the Commission, in such form as the
12    Commission shall require, a report as to the reconciliation
13    account. The annual report must contain the following
14    information:
15            (A) the revenue share target amount;
16            (B) the amount credited or debited to the
17        reconciliation account during the year;
18            (C) the amount credited to the utilities to be used
19        to reduce the utilities natural gas costs though the
20        purchase gas adjustment clause;
21            (D) the total amount of reconciliation account at
22        the beginning and end of the year;
23            (E) the total amount of consumer savings to date;
24        and
25            (F) any additional information the Commission may
26        require.

 

 

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1    When any report is erroneous or defective or appears to the
2Commission to be erroneous or defective, the Commission may
3notify the clean coal SNG facility to amend the report within
430 days; before or after the termination of the 30-day period,
5the Commission may examine the trustee of the reconciliation
6account or the officers, agents, employees, books, records, or
7accounts of the clean coal SNG facility and correct such items
8in the report as upon such examination the Commission may find
9defective or erroneous. All reports shall be under oath.
10    All reports made to the Commission by the clean coal SNG
11facility and the contents of the reports shall be open to
12public inspection and shall be deemed a public record under the
13Freedom of Information Act. Such reports shall be preserved in
14the office of the Commission. The Commission shall publish an
15annual summary of the reports prior to February 1 of the
16following year. The annual summary shall be made available to
17the public on the Commission's website and shall be submitted
18to the General Assembly.
19    Any facility that fails to file the report required under
20this paragraph (4) to the Commission within the time specified
21or to make specific answer to any question propounded by the
22Commission within 30 days after the time it is lawfully
23required to do so, or within such further time not to exceed 90
24days as may be allowed by the Commission in its discretion,
25shall pay a penalty of $500 to the Commission for each day it
26is in default.

 

 

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1    Any person who willfully makes any false report to the
2Commission or to any member, officer, or employee thereof, any
3person who willfully in a report withholds or fails to provide
4material information to which the Commission is entitled under
5this paragraph (4) and which information is either required to
6be filed by statute, rule, regulation, order, or decision of
7the Commission or has been requested by the Commission, and any
8person who willfully aids or abets such person shall be guilty
9of a Class A misdemeanor.
10    With respect to each contract entered into by the company
11with an Illinois utility in accordance with the terms stated in
12subsection (h) of this Section, within 60 days following the
13completion of purchases of SNG, the Illinois Power Agency shall
14conduct an analysis to determine (i) the average contract SNG
15cost, which shall be calculated as the total amount paid to a
16company for SNG over the contract term, plus the cost to the
17utility of the required transportation and storage services of
18SNG, divided by the total number of MMBtus of SNG actually
19purchased under the utility contract; (ii) the average natural
20gas purchase cost, which shall be calculated as the total
21annual supply costs paid for natural gas (excluding SNG)
22purchased by such utility over the contract term, plus the
23costs of transportation and storage services of such natural
24gas (excluding such costs for SNG), divided by the total number
25of MMBtus of natural gas (excluding SNG) actually purchased by
26the utility during the contract term; (iii) the cost

 

 

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1differential, which shall be the difference between the average
2contract SNG cost and the average natural gas purchase cost;
3and (iv) the revenue share target, which shall be the cost
4differential multiplied by the total amount of SNG purchased
5under such utility contract. If the average contract SNG cost
6is equal to or less than the average natural gas purchase cost,
7then the company shall have no further obligation to the
8utility. If the average contract SNG cost for such SNG contract
9is greater than the average natural gas purchase cost for such
10utility, then the company shall market the daily production of
11SNG and distribute on a monthly basis 5% of amounts collected
12with respect to such future sales to the utilities in
13proportion to each utility's SNG purchases from the company
14during the term of the SNG contract to be used to reduce the
15utility's natural gas costs through the purchased gas
16adjustment clause; such payments to the utility shall continue
17until such time as the sum of such payments equals the revenue
18share target of that utility. The company or utilities shall
19have no obligation to repay the revenue share target except as
20provided for in this subsection (h-15).
21    (h-20) The General Assembly authorizes the Illinois
22Finance Authority to issue bonds to the maximum extent
23permitted to finance coal gasification facilities described in
24this Section, which constitute both "industrial projects"
25under Article 801 of the Illinois Finance Authority Act and
26"clean coal and energy projects" under Sections 825-65 through

 

 

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1825-75 of the Illinois Finance Authority Act. The General
2Assembly further authorizes the Illinois Power Agency to become
3party to agreements and take such actions as necessary to
4enable the Illinois Power Agency or its designate to (i) review
5and confirm in writing that the terms stated in subsection (h)
6of this Section are incorporated in the SNG contract, and (ii)
7conduct an analysis pursuant to subsection (h-15) of this
8Section.
9    Administrative costs incurred by the Illinois Finance
10Authority and Illinois Power Agency in performance of this
11subsection (h-20) shall be subject to reimbursement by the
12clean coal SNG facility company on terms as the Illinois
13Finance Authority, the Illinois Power Agency, and the clean
14coal SNG facility company may agree. The utility and its
15customers shall have no obligation to reimburse the clean coal
16SNG facility or company, the Illinois Finance Authority, or the
17Illinois Power Agency for any such costs.
18    (h-25) The State of Illinois pledges that the State may not
19enact any law or take any action to (1) break or repeal the
20authority for SNG purchase contracts entered into between
21public gas utilities and the clean coal SNG facility pursuant
22to subsection (h) of this Section or (2) deny public gas
23utilities their full cost recovery for contract costs, as
24defined in subsection (h-10), that are incurred under such SNG
25purchase contracts. These pledges are for the benefit of the
26parties to such SNG purchase contracts and the issuers and

 

 

SB2169 Enrolled- 51 -LRB097 07925 ASK 48040 b

1holders of bonds or other obligations issued or incurred to
2finance or refinance the clean coal SNG facility. The
3beneficiaries are authorized to include and refer to these
4pledges in any finance agreement into which they may enter in
5regard to such contracts.
6    (h-30) The State of Illinois retains and reserves all other
7rights to enact new or amendatory legislation or take any other
8action, including, but not limited to, such legislation or
9other action that would (1) directly or indirectly raise the
10costs that the clean coal SNG facility must incur; (2) directly
11or indirectly place additional restrictions, regulations, or
12requirements on the clean coal SNG facility; (3) prohibit
13sequestration in general or prohibit a specific sequestration
14method or project; or (4) increase minimum sequestration
15requirements.
16    (i) If a gas utility or an affiliate of a gas utility has
17an ownership interest in any entity that produces or sells
18synthetic natural gas, Article VII of this Act shall apply.
19(Source: P.A. 95-1027, eff. 6-1-09; 96-1364, eff. 7-28-10.)
 
20    Section 20. The Illinois Gas Pipeline Safety Act is amended
21by changing Sections 2.02, 2.03, 2.04, and 3 as follows:
 
22    (220 ILCS 20/2.02)  (from Ch. 111 2/3, par. 552.2)
23    Sec. 2.02.
24    "Gas" means natural gas, flammable gas or gas which is

 

 

SB2169 Enrolled- 52 -LRB097 07925 ASK 48040 b

1toxic or corrosive. "Gas" also means carbon dioxide in any
2physical form, whenever transported by pipeline for the purpose
3of sequestration.
4(Source: P.A. 76-1588.)
 
5    (220 ILCS 20/2.03)  (from Ch. 111 2/3, par. 552.3)
6    Sec. 2.03. "Transportation of gas" means the gathering,
7transmission, or distribution of gas by pipeline or its
8storage, within this State and not subject to the jurisdiction
9of the Federal Energy Regulatory Commission under the Natural
10Gas Act, except that it includes the transmission of gas
11through pipeline facilities within this State that transport
12gas from an interstate gas pipeline to a direct sales customer
13within this State purchasing gas for its own consumption.
14"Transportation of gas" also includes the conveyance of gas
15from a gas main through the primary fuel line to the outside
16wall of residential premises. If the gas meter is placed within
173 feet of the structure, the utility's responsibility shall end
18at the outlet side of the meter. "Transportation of gas" also
19includes the conveyance of carbon dioxide in any physical form
20for the purpose of sequestration.
21(Source: P.A. 87-1092; 88-314.)
 
22    (220 ILCS 20/2.04)  (from Ch. 111 2/3, par. 552.4)
23    Sec. 2.04. "Pipeline facilities" includes new and existing
24pipe rights-of-way and any equipment, facility, or building

 

 

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1used in the transportation of gas or the treatment of gas
2during the course of transportation and includes facilities
3within this State that transport gas from an interstate gas
4pipeline to a direct sales customer within this State
5purchasing gas for its own consumption, but "rights-of-way" as
6used in this Act does not authorize the Commission to
7prescribe, under this Act, the location or routing of any
8pipeline facility. "Pipeline facilities" also includes new and
9existing pipes and lines and any other equipment, facility, or
10structure, except customer-owned branch lines connected to the
11primary fuel lines, used to convey gas from a gas main to the
12outside wall of residential premises, and any person who
13provides gas service directly to its residential customer
14through these facilities shall be deemed to operate such
15pipeline facilities for purposes of this Act irrespective of
16the ownership of the facilities or the location of the
17facilities with respect to the meter, except that a person who
18provides gas service to a "master meter system", as that term
19is defined at 49 C.F.R. Section 191.3, shall not be deemed to
20operate any facilities downstream of the master meter.
21"Pipeline facilities" also includes new and existing pipe
22rights-of-way and any equipment, facility, or building used in
23the transportation of carbon dioxide in any physical form for
24the purpose of sequestration.
25(Source: P.A. 87-1092; 88-314.)
 

 

 

SB2169 Enrolled- 54 -LRB097 07925 ASK 48040 b

1    (220 ILCS 20/3)  (from Ch. 111 2/3, par. 553)
2    Sec. 3. (a) As soon as practicable, but not later than 3
3months after the effective date of this Act, the Commission
4shall adopt rules establishing minimum safety standards for the
5transportation of gas and for pipeline facilities. Such rules
6shall be at least as inclusive, as stringent, and compatible
7with, the minimum safety standards adopted by the Secretary of
8Transportation under the Federal Act. Thereafter, the
9Commission shall maintain such rules so that the rules are at
10least as inclusive, as stringent, and compatible with, the
11minimum standards from time to time in effect under the Federal
12Act. The Commission shall also adopt rules establishing minimum
13safety standards for the transportation of carbon dioxide in
14any physical form for the purpose of sequestration and for
15pipeline facilities used for that function.
16    (b) Standards established under this Act may apply to the
17design, installation, inspection, testing, construction,
18extension, operation, replacement, and maintenance of pipeline
19facilities. Standards affecting the design, installation,
20construction, initial inspection and initial testing are not
21applicable to pipeline facilities in existence on the date such
22standards are adopted. Whenever the Commission finds a
23particular facility to be hazardous to life or property, it may
24require the person operating such facility to take the steps
25necessary to remove the hazard.
26    (c) Standards established by the Commission under this Act

 

 

SB2169 Enrolled- 55 -LRB097 07925 ASK 48040 b

1shall, subject to paragraphs (a) and (b) of this Section 3, be
2practicable and designed to meet the need for pipeline safety.
3In prescribing such standards, the Commission shall consider:
4similar standards established in other states; relevant
5available pipeline safety data; whether such standards are
6appropriate for the particular type of pipeline
7transportation; the reasonableness of any proposed standards;
8and the extent to which such standards will contribute to
9public safety.
10    Rules adopted under this Act are subject to "The Illinois
11Administrative Procedure Act", approved September 22, 1975, as
12amended.
13(Source: P.A. 83-333.)
 
14    Section 25. The Environmental Protection Act is amended by
15adding Section 13.7 as follows:
 
16    (415 ILCS 5/13.7 new)
17    Sec. 13.7. Carbon dioxide sequestration sites.
18    (a) For purposes of this Section, the term "carbon dioxide
19sequestration site" means a site or facility for which the
20Agency has issued a permit for the underground injection of
21carbon dioxide.
22    (b) The Agency shall inspect carbon dioxide sequestration
23sites for compliance with this Act, rules adopted under this
24Act, and permits issued by the Agency.

 

 

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1    (c) If the Agency issues a seal order under Section 34 of
2this Act in relation to a carbon dioxide sequestration site, or
3if a civil action for an injunction to halt activity at a
4carbon dioxide sequestration site is initiated under Section 43
5of this Act at the request of the Agency, then the Agency shall
6post notice of such action on its website.
7    (d) Persons seeking a permit or permit modification for the
8underground injection of carbon dioxide shall be liable to the
9Agency for all reasonable and documented costs incurred by the
10Agency that are associated with review and issuance of the
11permit, including, but not limited to, costs associated with
12public hearings and the review of permit applications. Once a
13permit is issued, the permittee shall be liable to the Agency
14for all reasonable and documented costs incurred by the Agency
15that are associated with inspections and other oversight of the
16carbon dioxide sequestration site. Persons liable for costs
17under this subsection (d) must pay the costs upon invoicing, or
18other request or demand for payment, by the Agency. Costs for
19which a person is liable under this subsection (d) are in
20addition to any other fees, penalties, or other relief provided
21under this Act or any other law.
22    Moneys collected under this subsection (d) shall be
23deposited into the Environmental Protection Permit and
24Inspection Fund established under Section 22.8 of this Act. The
25Agency may adopt rules relating to the collection of costs due
26under this subsection (d).

 

 

SB2169 Enrolled- 57 -LRB097 07925 ASK 48040 b

1    (e) The Agency shall not issue a permit or permit
2modification for the underground injection of carbon dioxide
3unless all costs for which the permittee is liable under
4subsection (d) of this Section have been paid.
5    (f) No person shall fail or refuse to pay costs for which
6the person is liable under subsection (d) of this Section.
 
7    Section 97. Inseverability. The provisions of this Act are
8mutually dependent and inseverable. If any provision is held
9invalid, then this entire Act, including all new and amendatory
10provisions, is invalid.
 
11    Section 99. Effective date. This Act takes effect upon
12becoming law.