Rep. Dan Reitz

Filed: 5/20/2011

 

 


 

 


 
09700SB2169ham001LRB097 07925 ASK 55966 a

1
AMENDMENT TO SENATE BILL 2169

2    AMENDMENT NO. ______. Amend Senate Bill 2169 by replacing
3everything after the enacting clause with the following:
 
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.

 

 

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1    "Authority" means the Illinois Finance Authority.
2    "Clean coal facility" means an electric generating
3facility that uses primarily coal as a feedstock and that
4captures and sequesters carbon dioxide emissions at the
5following levels: at least 50% of the total carbon dioxide
6emissions that the facility would otherwise emit if, at the
7time construction commences, the facility is scheduled to
8commence operation before 2016, at least 70% of the total
9carbon dioxide emissions that the facility would otherwise emit
10if, at the time construction commences, the facility is
11scheduled to commence operation during 2016 or 2017, and at
12least 90% of the total carbon dioxide emissions that the
13facility would otherwise emit if, at the time construction
14commences, the facility is scheduled to commence operation
15after 2017. The power block of the clean coal facility shall
16not exceed allowable emission rates for sulfur dioxide,
17nitrogen oxides, carbon monoxide, particulates and mercury for
18a natural gas-fired combined-cycle facility the same size as
19and in the same location as the clean coal facility at the time
20the clean coal facility obtains an approved air permit. All
21coal used by a clean coal facility shall have high volatile
22bituminous rank and greater than 1.7 pounds of sulfur per
23million btu content, unless the clean coal facility does not
24use gasification technology and was operating as a conventional
25coal-fired electric generating facility on June 1, 2009 (the
26effective date of Public Act 95-1027).

 

 

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1    "Clean coal SNG facility" means a facility that uses a
2gasification process to produce substitute natural gas, that
3sequesters at least 90% of the total carbon emissions that the
4facility would otherwise emit, and that uses at least 90%
5petroleum coke or coal as a feedstock, with all such coal
6having a high bituminous rank and greater than 1.7 pounds of
7sulfur per million btu content, and that has a valid and
8effective permit to construct emission sources and air
9pollution control equipment and approval with respect to the
10federal regulations for Prevention of Significant
11Deterioration of Air Quality (PSD) for the plant pursuant to
12the federal Clean Air Act.
13    "Commission" means the Illinois Commerce Commission.
14    "Costs incurred in connection with the development and
15construction of a facility" means:
16        (1) the cost of acquisition of all real property,
17    fixtures, and improvements in connection therewith and
18    equipment, personal property, and other property, rights,
19    and easements acquired that are deemed necessary for the
20    operation and maintenance of the facility;
21        (2) financing costs with respect to bonds, notes, and
22    other evidences of indebtedness of the Agency;
23        (3) all origination, commitment, utilization,
24    facility, placement, underwriting, syndication, credit
25    enhancement, and rating agency fees;
26        (4) engineering, design, procurement, consulting,

 

 

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1    legal, accounting, title insurance, survey, appraisal,
2    escrow, trustee, collateral agency, interest rate hedging,
3    interest rate swap, capitalized interest, contingency, as
4    required by lenders, and other financing costs, and other
5    expenses for professional services; and
6        (5) the costs of plans, specifications, site study and
7    investigation, installation, surveys, other Agency costs
8    and estimates of costs, and other expenses necessary or
9    incidental to determining the feasibility of any project,
10    together with such other expenses as may be necessary or
11    incidental to the financing, insuring, acquisition, and
12    construction of a specific project and starting up,
13    commissioning, and placing that project in operation.
14    "Department" means the Department of Commerce and Economic
15Opportunity.
16    "Director" means the Director of the Illinois Power Agency.
17    "Demand-response" means measures that decrease peak
18electricity demand or shift demand from peak to off-peak
19periods.
20    "Energy efficiency" means measures that reduce the amount
21of electricity or natural gas required to achieve a given end
22use.
23    "Electric utility" has the same definition as found in
24Section 16-102 of the Public Utilities Act.
25    "Facility" means an electric generating unit or a
26co-generating unit that produces electricity along with

 

 

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1related equipment necessary to connect the facility to an
2electric transmission or distribution system.
3    "Governmental aggregator" means one or more units of local
4government that individually or collectively procure
5electricity to serve residential retail electrical loads
6located within its or their jurisdiction.
7    "Local government" means a unit of local government as
8defined in Article VII of Section 1 of the Illinois
9Constitution.
10    "Municipality" means a city, village, or incorporated
11town.
12    "Person" means any natural person, firm, partnership,
13corporation, either domestic or foreign, company, association,
14limited liability company, joint stock company, or association
15and includes any trustee, receiver, assignee, or personal
16representative thereof.
17    "Project" means the planning, bidding, and construction of
18a facility.
19    "Public utility" has the same definition as found in
20Section 3-105 of the Public Utilities Act.
21    "Real property" means any interest in land together with
22all structures, fixtures, and improvements thereon, including
23lands under water and riparian rights, any easements,
24covenants, licenses, leases, rights-of-way, uses, and other
25interests, together with any liens, judgments, mortgages, or
26other claims or security interests related to real property.

 

 

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1    "Renewable energy credit" means a tradable credit that
2represents the environmental attributes of a certain amount of
3energy produced from a renewable energy resource.
4    "Renewable energy resources" includes energy and its
5associated renewable energy credit or renewable energy credits
6from wind, solar thermal energy, photovoltaic cells and panels,
7biodiesel, crops and untreated and unadulterated organic waste
8biomass, tree waste, hydropower that does not involve new
9construction or significant expansion of hydropower dams, and
10other alternative sources of environmentally preferable
11energy. For purposes of this Act, landfill gas produced in the
12State is considered a renewable energy resource. "Renewable
13energy resources" does not include the incineration or burning
14of tires, garbage, general household, institutional, and
15commercial waste, industrial lunchroom or office waste,
16landscape waste other than tree waste, railroad crossties,
17utility poles, or construction or demolition debris, other than
18untreated and unadulterated waste wood.
19    "Revenue bond" means any bond, note, or other evidence of
20indebtedness issued by the Authority, the principal and
21interest of which is payable solely from revenues or income
22derived from any project or activity of the Agency.
23    "Sequester" means permanent storage of carbon dioxide by
24injecting it into a saline aquifer, a depleted gas reservoir,
25or an oil reservoir, directly or through an enhanced oil
26recovery process that may involve intermediate storage,

 

 

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1regardless of whether these activities are conducted by a clean
2coal facility, a clean coal SNG facility, or a party with which
3a clean coal facility or clean coal SNG facility has contracted
4for such purposes in a salt dome.
5    "Servicing agreement" means (i) in the case of an electric
6utility, an agreement between the owner of a clean coal
7facility and such electric utility, which agreement shall have
8terms and conditions meeting the requirements of paragraph (3)
9of subsection (d) of Section 1-75, and (ii) in the case of an
10alternative retail electric supplier, an agreement between the
11owner of a clean coal facility and such alternative retail
12electric supplier, which agreement shall have terms and
13conditions meeting the requirements of Section 16-115(d)(5) of
14the Public Utilities Act.
15    "Substitute natural gas" or "SNG" means a gas manufactured
16by gasification of hydrocarbon feedstock, which is
17substantially interchangeable in use and distribution with
18conventional natural gas.
19    "Total resource cost test" or "TRC test" means a standard
20that is met if, for an investment in energy efficiency or
21demand-response measures, the benefit-cost ratio is greater
22than one. The benefit-cost ratio is the ratio of the net
23present value of the total benefits of the program to the net
24present value of the total costs as calculated over the
25lifetime of the measures. A total resource cost test compares
26the sum of avoided electric utility costs, representing the

 

 

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1benefits that accrue to the system and the participant in the
2delivery of those efficiency measures, as well as other
3quantifiable societal benefits, including avoided natural gas
4utility costs, to the sum of all incremental costs of end-use
5measures that are implemented due to the program (including
6both utility and participant contributions), plus costs to
7administer, deliver, and evaluate each demand-side program, to
8quantify the net savings obtained by substituting the
9demand-side program for supply resources. In calculating
10avoided costs of power and energy that an electric utility
11would otherwise have had to acquire, reasonable estimates shall
12be included of financial costs likely to be imposed by future
13regulations and legislation on emissions of greenhouse gases.
14(Source: P.A. 95-481, eff. 8-28-07; 95-913, eff. 1-1-09;
1595-1027, eff. 6-1-09; 96-33, eff. 7-10-09; 96-159, eff.
168-10-09; 96-784, eff. 8-28-09; 96-1000, eff. 7-2-10.)
 
17    Section 10. The Illinois Procurement Code is amended by
18changing Section 1-10 as follows:
 
19    (30 ILCS 500/1-10)
20    Sec. 1-10. Application.
21    (a) This Code applies only to procurements for which
22contractors were first solicited on or after July 1, 1998. This
23Code shall not be construed to affect or impair any contract,
24or any provision of a contract, entered into based on a

 

 

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1solicitation prior to the implementation date of this Code as
2described in Article 99, including but not limited to any
3covenant entered into with respect to any revenue bonds or
4similar instruments. All procurements for which contracts are
5solicited between the effective date of Articles 50 and 99 and
6July 1, 1998 shall be substantially in accordance with this
7Code and its intent.
8    (b) This Code shall apply regardless of the source of the
9funds with which the contracts are paid, including federal
10assistance moneys. This Code shall not apply to:
11        (1) Contracts between the State and its political
12    subdivisions or other governments, or between State
13    governmental bodies except as specifically provided in
14    this Code.
15        (2) Grants, except for the filing requirements of
16    Section 20-80.
17        (3) Purchase of care.
18        (4) Hiring of an individual as employee and not as an
19    independent contractor, whether pursuant to an employment
20    code or policy or by contract directly with that
21    individual.
22        (5) Collective bargaining contracts.
23        (6) Purchase of real estate, except that notice of this
24    type of contract with a value of more than $25,000 must be
25    published in the Procurement Bulletin within 7 days after
26    the deed is recorded in the county of jurisdiction. The

 

 

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1    notice shall identify the real estate purchased, the names
2    of all parties to the contract, the value of the contract,
3    and the effective date of the contract.
4        (7) Contracts necessary to prepare for anticipated
5    litigation, enforcement actions, or investigations,
6    provided that the chief legal counsel to the Governor shall
7    give his or her prior approval when the procuring agency is
8    one subject to the jurisdiction of the Governor, and
9    provided that the chief legal counsel of any other
10    procuring entity subject to this Code shall give his or her
11    prior approval when the procuring entity is not one subject
12    to the jurisdiction of the Governor.
13        (8) Contracts for services to Northern Illinois
14    University by a person, acting as an independent
15    contractor, who is qualified by education, experience, and
16    technical ability and is selected by negotiation for the
17    purpose of providing non-credit educational service
18    activities or products by means of specialized programs
19    offered by the university.
20        (9) Procurement expenditures by the Illinois
21    Conservation Foundation when only private funds are used.
22        (10) Procurement expenditures by the Illinois Health
23    Information Exchange Authority involving private funds
24    from the Health Information Exchange Fund. "Private funds"
25    means gifts, donations, and private grants.
26    (c) This Code does not apply to the electric power

 

 

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1procurement process provided for under Section 1-75 of the
2Illinois Power Agency Act and Section 16-111.5 of the Public
3Utilities Act.
4    (d) Except for Section 20-160 and Article 50 of this Code,
5and as expressly required by Section 9.1 of the Illinois
6Lottery Law, the provisions of this Code do not apply to the
7procurement process provided for under Section 9.1 of the
8Illinois Lottery Law.
9    (e) This Code does not apply to the processes used by the
10Illinois Power Agency to retain a mediator to mediate contract
11disputes between gas utilities and the clean coal SNG facility
12and to retain an expert to assist in the review of contracts
13under subsection (h) of Section 9-220 of the Public Utilities
14Act. This Code does not apply to the process used by the
15Illinois Commerce Commission to retain an expert to assist in
16determining the actual incurred costs of the clean coal SNG
17facility and the reasonableness of those costs as required
18under subsection (h) of Section 9-220 of the Public Utilities
19Act.
20(Source: P.A. 95-481, eff. 8-28-07; 95-615, eff. 9-11-07;
2195-876, eff. 8-21-08; 96-840, eff. 12-23-09; 96-1331, eff.
227-27-10.)
 
23    Section 15. The Public Utilities Act is amended by changing
24Sections 3-101 and 9-220 and by adding Sections 3-123, 3-124,
253-125, and 3-126 as follows:
 

 

 

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1    (220 ILCS 5/3-101)  (from Ch. 111 2/3, par. 3-101)
2    Sec. 3-101. Definitions. Unless otherwise specified, the
3terms set forth in Sections 3-102 through 3-126 3-121 are used
4in this Act as therein defined.
5(Source: P.A. 84-617; 84-1118.)
 
6    (220 ILCS 5/3-123 new)
7    Sec. 3-123. Clean coal facility; clean coal SNG facility;
8sequester; SNG facility; substitute natural gas or SNG. As used
9in this Act:
10    "Clean coal facility" shall have the same meaning as
11provided in Section 1-10 of the Illinois Power Agency Act.
12    "Clean coal SNG facility" shall have the same meaning as
13provided in Section 1-10 of the Illinois Power Agency Act.
14    "Sequester" shall have the same meaning as provided in
15Section 1-10 of the Illinois Power Agency Act.
16    "SNG facility" means a facility that produces substitute
17natural gas from feedstock that includes coal through a
18gasification process, including a clean coal facility, and the
19clean coal SNG facility described in subsection (h) of Section
209-220 of this Act.
21    "Substitute natural gas" or "SNG" shall have the same
22meaning as provided in Section 1-10 of the Illinois Power
23Agency Act.
 

 

 

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1    (220 ILCS 5/3-124 new)
2    Sec. 3-124. Adjusted final capitalized plant cost.
3"Adjusted final capitalized plant cost" means the final
4capitalized plant cost reduced by the following, without
5duplication and to the extent not already accounted for or
6reflected on the books of the facility: (1) any State of
7Illinois financial assistance, (2) any U.S. financial
8assistance, and (3) any quantifiable benefit from a U.S. Clean
9Coal Gasification Program received by the facility during a
10period equal to the shorter of (A) the life of such program or
11(B) the term of the agreement, such quantifiable benefit to be
12discounted at a rate of 14% per annum over such period.
 
13    (220 ILCS 5/3-125 new)
14    Sec. 3-125. Final capitalized plant cost. "Final
15capitalized plant cost" means the total capitalized asset cost
16of the plant of the clean coal SNG facility as reflected on the
17balance sheet of the facility at the time of the commercial
18production date, with such capitalized cost to be accrued in
19accordance with generally accepted accounting principles, and
20includes, without limitation, the following items: major
21equipment, the SNG pipeline from the plant to the receiving
22pipeline, water lines, railroad improvements, access road
23improvements, all coal transportation assets, including the
24slurry line, slurry prep plant, carbon dioxide capture metering
25and compression, licensing fees, all costs incurred in the

 

 

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1management planning, oversight and execution of the
2construction and start-up of the plant, and all fees and costs
3payable under engineering, procurement, and design contracts
4for the construct of the plant accrued as of the time of the
5commercial production date, but does not include capitalized
6financing costs including capitalized interest during
7construction and all fees associated with financing, coal
8reserve leasing costs, marketing, training, any and all costs
9payable under the contract miner agreement, the cost of coal
10mining equipment and similar costs, and any other costs,
11including general and administrative costs, not reasonably
12incurred in connection with the design, construction, testing,
13start-up, or commissioning of the plant in preparation for
14commercial production date.
 
15    (220 ILCS 5/3-126 new)
16    Sec. 3-126. Total capitalized asset cost. "Total
17capitalized asset cost" means the gross book value of the
18plant, as determined in accordance with generally accepted
19accounting principles at the commercial production date.
 
20    (220 ILCS 5/9-220)  (from Ch. 111 2/3, par. 9-220)
21    Sec. 9-220. Rate changes based on changes in fuel costs.
22    (a) Notwithstanding the provisions of Section 9-201, the
23Commission may authorize the increase or decrease of rates and
24charges based upon changes in the cost of fuel used in the

 

 

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1generation or production of electric power, changes in the cost
2of purchased power, or changes in the cost of purchased gas
3through the application of fuel adjustment clauses or purchased
4gas adjustment clauses. The Commission may also authorize the
5increase or decrease of rates and charges based upon
6expenditures or revenues resulting from the purchase or sale of
7emission allowances created under the federal Clean Air Act
8Amendments of 1990, through such fuel adjustment clauses, as a
9cost of fuel. For the purposes of this paragraph, cost of fuel
10used in the generation or production of electric power shall
11include the amount of any fees paid by the utility for the
12implementation and operation of a process for the
13desulfurization of the flue gas when burning high sulfur coal
14at any location within the State of Illinois irrespective of
15the attainment status designation of such location; but shall
16not include transportation costs of coal (i) except to the
17extent that for contracts entered into on and after the
18effective date of this amendatory Act of 1997, the cost of the
19coal, including transportation costs, constitutes the lowest
20cost for adequate and reliable fuel supply reasonably available
21to the public utility in comparison to the cost, including
22transportation costs, of other adequate and reliable sources of
23fuel supply reasonably available to the public utility, or (ii)
24except as otherwise provided in the next 3 sentences of this
25paragraph. Such costs of fuel shall, when requested by a
26utility or at the conclusion of the utility's next general

 

 

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1electric rate proceeding, whichever shall first occur, include
2transportation costs of coal purchased under existing coal
3purchase contracts. For purposes of this paragraph "existing
4coal purchase contracts" means contracts for the purchase of
5coal in effect on the effective date of this amendatory Act of
61991, as such contracts may thereafter be amended, but only to
7the extent that any such amendment does not increase the
8aggregate quantity of coal to be purchased under such contract.
9Nothing herein shall authorize an electric utility to recover
10through its fuel adjustment clause any amounts of
11transportation costs of coal that were included in the revenue
12requirement used to set base rates in its most recent general
13rate proceeding. Cost shall be based upon uniformly applied
14accounting principles. Annually, the Commission shall initiate
15public hearings to determine whether the clauses reflect actual
16costs of fuel, gas, power, or coal transportation purchased to
17determine whether such purchases were prudent, and to reconcile
18any amounts collected with the actual costs of fuel, power,
19gas, or coal transportation prudently purchased. In each such
20proceeding, the burden of proof shall be upon the utility to
21establish the prudence of its cost of fuel, power, gas, or coal
22transportation purchases and costs. The Commission shall issue
23its final order in each such annual proceeding for an electric
24utility by December 31 of the year immediately following the
25year to which the proceeding pertains, provided, that the
26Commission shall issue its final order with respect to such

 

 

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1annual proceeding for the years 1996 and earlier by December
231, 1998.
3    (b) A public utility providing electric service, other than
4a public utility described in subsections (e) or (f) of this
5Section, may at any time during the mandatory transition period
6file with the Commission proposed tariff sheets that eliminate
7the public utility's fuel adjustment clause and adjust the
8public utility's base rate tariffs by the amount necessary for
9the base fuel component of the base rates to recover the public
10utility's average fuel and power supply costs per kilowatt-hour
11for the 2 most recent years for which the Commission has issued
12final orders in annual proceedings pursuant to subsection (a),
13where the average fuel and power supply costs per kilowatt-hour
14shall be calculated as the sum of the public utility's prudent
15and allowable fuel and power supply costs as found by the
16Commission in the 2 proceedings divided by the public utility's
17actual jurisdictional kilowatt-hour sales for those 2 years.
18Notwithstanding any contrary or inconsistent provisions in
19Section 9-201 of this Act, in subsection (a) of this Section or
20in any rules or regulations promulgated by the Commission
21pursuant to subsection (g) of this Section, the Commission
22shall review and shall by order approve, or approve as
23modified, the proposed tariff sheets within 60 days after the
24date of the public utility's filing. The Commission may modify
25the public utility's proposed tariff sheets only to the extent
26the Commission finds necessary to achieve conformance to the

 

 

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1requirements of this subsection (b). During the 5 years
2following the date of the Commission's order, but in any event
3no earlier than January 1, 2007, a public utility whose fuel
4adjustment clause has been eliminated pursuant to this
5subsection shall not file proposed tariff sheets seeking, or
6otherwise petition the Commission for, reinstatement of a fuel
7adjustment clause.
8    (c) Notwithstanding any contrary or inconsistent
9provisions in Section 9-201 of this Act, in subsection (a) of
10this Section or in any rules or regulations promulgated by the
11Commission pursuant to subsection (g) of this Section, a public
12utility providing electric service, other than a public utility
13described in subsection (e) or (f) of this Section, may at any
14time during the mandatory transition period file with the
15Commission proposed tariff sheets that establish the rate per
16kilowatt-hour to be applied pursuant to the public utility's
17fuel adjustment clause at the average value for such rate
18during the preceding 24 months, provided that such average rate
19results in a credit to customers' bills, without making any
20revisions to the public utility's base rate tariffs. The
21proposed tariff sheets shall establish the fuel adjustment rate
22for a specific time period of at least 3 years but not more
23than 5 years, provided that the terms and conditions for any
24reinstatement earlier than 5 years shall be set forth in the
25proposed tariff sheets and subject to modification or approval
26by the Commission. The Commission shall review and shall by

 

 

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1order approve the proposed tariff sheets if it finds that the
2requirements of this subsection are met. The Commission shall
3not conduct the annual hearings specified in the last 3
4sentences of subsection (a) of this Section for the utility for
5the period that the factor established pursuant to this
6subsection is in effect.
7    (d) A public utility providing electric service, or a
8public utility providing gas service may file with the
9Commission proposed tariff sheets that eliminate the public
10utility's fuel or purchased gas adjustment clause and adjust
11the public utility's base rate tariffs to provide for recovery
12of power supply costs or gas supply costs that would have been
13recovered through such clause; provided, that the provisions of
14this subsection (d) shall not be available to a public utility
15described in subsections (e) or (f) of this Section to
16eliminate its fuel adjustment clause. Notwithstanding any
17contrary or inconsistent provisions in Section 9-201 of this
18Act, in subsection (a) of this Section, or in any rules or
19regulations promulgated by the Commission pursuant to
20subsection (g) of this Section, the Commission shall review and
21shall by order approve, or approve as modified in the
22Commission's order, the proposed tariff sheets within 240 days
23after the date of the public utility's filing. The Commission's
24order shall approve rates and charges that the Commission,
25based on information in the public utility's filing or on the
26record if a hearing is held by the Commission, finds will

 

 

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1recover the reasonable, prudent and necessary jurisdictional
2power supply costs or gas supply costs incurred or to be
3incurred by the public utility during a 12 month period found
4by the Commission to be appropriate for these purposes,
5provided, that such period shall be either (i) a 12 month
6historical period occurring during the 15 months ending on the
7date of the public utility's filing, or (ii) a 12 month future
8period ending no later than 15 months following the date of the
9public utility's filing. The public utility shall include with
10its tariff filing information showing both (1) its actual
11jurisdictional power supply costs or gas supply costs for a 12
12month historical period conforming to (i) above and (2) its
13projected jurisdictional power supply costs or gas supply costs
14for a future 12 month period conforming to (ii) above. If the
15Commission's order requires modifications in the tariff sheets
16filed by the public utility, the public utility shall have 7
17days following the date of the order to notify the Commission
18whether the public utility will implement the modified tariffs
19or elect to continue its fuel or purchased gas adjustment
20clause in force as though no order had been entered. The
21Commission's order shall provide for any reconciliation of
22power supply costs or gas supply costs, as the case may be, and
23associated revenues through the date that the public utility's
24fuel or purchased gas adjustment clause is eliminated. During
25the 5 years following the date of the Commission's order, a
26public utility whose fuel or purchased gas adjustment clause

 

 

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1has been eliminated pursuant to this subsection shall not file
2proposed tariff sheets seeking, or otherwise petition the
3Commission for, reinstatement or adoption of a fuel or
4purchased gas adjustment clause. Nothing in this subsection (d)
5shall be construed as limiting the Commission's authority to
6eliminate a public utility's fuel adjustment clause or
7purchased gas adjustment clause in accordance with any other
8applicable provisions of this Act.
9    (e) Notwithstanding any contrary or inconsistent
10provisions in Section 9-201 of this Act, in subsection (a) of
11this Section, or in any rules promulgated by the Commission
12pursuant to subsection (g) of this Section, a public utility
13providing electric service to more than 1,000,000 customers in
14this State may, within the first 6 months after the effective
15date of this amendatory Act of 1997, file with the Commission
16proposed tariff sheets that eliminate, effective January 1,
171997, the public utility's fuel adjustment clause without
18adjusting its base rates, and such tariff sheets shall be
19effective upon filing. To the extent the application of the
20fuel adjustment clause had resulted in net charges to customers
21after January 1, 1997, the utility shall also file a tariff
22sheet that provides for a refund stated on a per kilowatt-hour
23basis of such charges over a period not to exceed 6 months;
24provided however, that such refund shall not include the
25proportional amounts of taxes paid under the Use Tax Act,
26Service Use Tax Act, Service Occupation Tax Act, and Retailers'

 

 

09700SB2169ham001- 22 -LRB097 07925 ASK 55966 a

1Occupation Tax Act on fuel used in generation. The Commission
2shall issue an order within 45 days after the date of the
3public utility's filing approving or approving as modified such
4tariff sheet. If the fuel adjustment clause is eliminated
5pursuant to this subsection, the Commission shall not conduct
6the annual hearings specified in the last 3 sentences of
7subsection (a) of this Section for the utility for any period
8after December 31, 1996 and prior to any reinstatement of such
9clause. A public utility whose fuel adjustment clause has been
10eliminated pursuant to this subsection shall not file a
11proposed tariff sheet seeking, or otherwise petition the
12Commission for, reinstatement of the fuel adjustment clause
13prior to January 1, 2007.
14    (f) Notwithstanding any contrary or inconsistent
15provisions in Section 9-201 of this Act, in subsection (a) of
16this Section, or in any rules or regulations promulgated by the
17Commission pursuant to subsection (g) of this Section, a public
18utility providing electric service to more than 500,000
19customers but fewer than 1,000,000 customers in this State may,
20within the first 6 months after the effective date of this
21amendatory Act of 1997, file with the Commission proposed
22tariff sheets that eliminate, effective January 1, 1997, the
23public utility's fuel adjustment clause and adjust its base
24rates by the amount necessary for the base fuel component of
25the base rates to recover 91% of the public utility's average
26fuel and power supply costs for the 2 most recent years for

 

 

09700SB2169ham001- 23 -LRB097 07925 ASK 55966 a

1which the Commission, as of January 1, 1997, has issued final
2orders in annual proceedings pursuant to subsection (a), where
3the average fuel and power supply costs per kilowatt-hour shall
4be calculated as the sum of the public utility's prudent and
5allowable fuel and power supply costs as found by the
6Commission in the 2 proceedings divided by the public utility's
7actual jurisdictional kilowatt-hour sales for those 2 years,
8provided, that such tariff sheets shall be effective upon
9filing. To the extent the application of the fuel adjustment
10clause had resulted in net charges to customers after January
111, 1997, the utility shall also file a tariff sheet that
12provides for a refund stated on a per kilowatt-hour basis of
13such charges over a period not to exceed 6 months. Provided
14however, that such refund shall not include the proportional
15amounts of taxes paid under the Use Tax Act, Service Use Tax
16Act, Service Occupation Tax Act, and Retailers' Occupation Tax
17Act on fuel used in generation. The Commission shall issue an
18order within 45 days after the date of the public utility's
19filing approving or approving as modified such tariff sheet. If
20the fuel adjustment clause is eliminated pursuant to this
21subsection, the Commission shall not conduct the annual
22hearings specified in the last 3 sentences of subsection (a) of
23this Section for the utility for any period after December 31,
241996 and prior to any reinstatement of such clause. A public
25utility whose fuel adjustment clause has been eliminated
26pursuant to this subsection shall not file a proposed tariff

 

 

09700SB2169ham001- 24 -LRB097 07925 ASK 55966 a

1sheet seeking, or otherwise petition the Commission for,
2reinstatement of the fuel adjustment clause prior to January 1,
32007.
4    (g) The Commission shall have authority to promulgate rules
5and regulations to carry out the provisions of this Section.
6    (h) Any Illinois gas utility may enter into a contract on
7or before March 31, 2011 for up to 10 years of supply with any
8company for the purchase of substitute natural gas (SNG)
9produced from coal through the gasification process if the
10company has commenced construction of a clean coal SNG
11gasification facility by July 1, 2012 in Jefferson County and
12commencement of construction shall mean that material physical
13site work has occurred, such as site clearing and excavation,
14water runoff prevention, water retention reservoir
15preparation, or foundation development. The contract shall
16contain the following provisions: (i) at least 90% of feedstock
17the only coal to be used in the gasification process shall be
18coal with a has high volatile bituminous rank and greater than
191.7 pounds of sulfur per million Btu content; (ii) at the time
20the contract term commences, the price per million Btu may not
21exceed $7.95 in 2008 dollars, adjusted annually based on the
22change in the Annual Consumer Price Index for All Urban
23Consumers for the Midwest Region as published in April by the
24United States Department of Labor, Bureau of Labor Statistics
25(or a suitable Consumer Price Index calculation if this
26Consumer Price Index is not available) for the previous

 

 

09700SB2169ham001- 25 -LRB097 07925 ASK 55966 a

1calendar year; provided that the price per million Btu shall
2not exceed $9.95 at any time during the contract; (iii) the
3utility's aggregate long-term supply contract contracts for
4the purchase of SNG does not exceed 15% 25% of the annual
5system supply requirements of the utility as of 2008 and the
6quantity of SNG supplied to a utility may not exceed 16 million
7MMBtus; and (iv) the contract costs pursuant to subsection
8(h-10) of this Section shall not include any lobbying expenses,
9charitable contributions, advertising, organizational
10memberships, carbon dioxide pipeline or sequestration
11expenses, or marketing expenses per year.
12    Any gas utility that is providing service to more than
13150,000 customers on the effective date of this amendatory Act
14of the 97th General Assembly shall either elect to enter into a
15contract on or before September 30, 2011 for 10 years of SNG
16supply with the owner of a clean coal SNG facility or to file
17biennial rate proceedings before the Commission in the years
182012, 2014, and 2016, with such filings made after the
19effective date of this amendatory Act of the 97th General
20Assembly and no later than September 30 of the years 2012,
212014, and 2016 consistent with all requirements of 83 Ill. Adm.
22Code 255 and 285 as though the gas utility were filing for an
23increase in its rates, without regard to whether such filing
24would produce an increase, a decrease, or no change in the gas
25utility's rates, and the Commission shall review the gas
26utility's filing and shall issue its order in accordance with

 

 

09700SB2169ham001- 26 -LRB097 07925 ASK 55966 a

1the provisions of Section 9-201 of this Act.
2    Within 7 days after the effective date of this amendatory
3Act of the 97th General Assembly, the owner of the clean coal
4SNG facility shall submit to the Illinois Power Agency and each
5gas utility that is providing service to more than 150,000
6customers on the effective date of this amendatory Act of the
797th General Assembly a copy of a draft contract. Within 30
8days after the receipt of the draft contract, each such gas
9utility shall provide the Illinois Power Agency and the owner
10of the clean coal SNG facility with its comments and
11recommended revisions to the draft contract. Within 7 days
12after the receipt of the gas utility's comments and recommended
13revisions, the owner of the facility shall submit its
14responsive comments and a further revised draft of the contract
15to the Illinois Power Agency. The Illinois Power Agency shall
16review the draft contract and comments.
17    During its review of the draft contract, the Illinois Power
18Agency shall:
19        (1) review and confirm in writing that the terms stated
20    in this subsection (h) are incorporated in the SNG
21    contract;
22        (2) review the SNG pricing formula included in the
23    contract and approve that formula if the Illinois Power
24    Agency determines that the formula, at the time the
25    contract term commences: (A) starts with a price of $6.50
26    per MMBtu adjusted by the adjusted final capitalized plant

 

 

09700SB2169ham001- 27 -LRB097 07925 ASK 55966 a

1    cost; (B) takes into account budgeted miscellaneous net
2    revenue after cost allowance, including sale of SNG
3    produced by the clean coal SNG facility above the nameplate
4    capacity of the facility and other by-products produced by
5    the facility, as approved by the Illinois Power Agency; (C)
6    does not include carbon dioxide transportation or
7    sequestration expenses; and (D) includes all provisions
8    required under this subsection (h); if the Illinois Power
9    Agency does not approve of the SNG pricing formula, then
10    the Illinois Power Agency shall modify the formula to
11    ensure that it meets the requirements of this subsection
12    (h);
13        (3) review and approve the amount of budgeted
14    miscellaneous net revenue after cost allowance, including
15    sale of SNG produced by the clean coal SNG facility above
16    the nameplate capacity of the facility and other
17    by-products produced by the facility, to be included in the
18    pricing formula; the Illinois Power Agency shall approve
19    the amount of budgeted miscellaneous net revenue to be
20    included in the pricing formula if it determines the
21    budgeted amount to be reasonable and accurate;
22        (4) review and confirm in writing that using the EIA
23    Annual Energy Outlook-2011 Henry Hub Spot Price, the
24    contract terms set out in subsection (h), the
25    reconciliation account terms as set out in subsection
26    (h-15), and an estimated inflation rate of 2.5%, that there

 

 

09700SB2169ham001- 28 -LRB097 07925 ASK 55966 a

1    will be no cumulative estimated increase for residential
2    customers; and
3        (5) allocate the nameplate capacity of the clean coal
4    SNG by total therms sold to ultimate customers by each gas
5    utility in 2008; provided, however, no utility shall be
6    required to purchase more than 42% of the projected annual
7    output of the facility; additionally, the Illinois Power
8    Agency shall further adjust the allocation only as required
9    to take into account (A) adverse consolidation,
10    derivative, or lease impacts to the balance sheet or income
11    statement of any gas utility or (B) the physical capacity
12    of the gas utility to accept SNG.
13    If the parties to the contract do not agree on the terms
14therein, then the Illinois Power Agency shall retain an
15independent mediator to mediate the dispute between the
16parties. If the parties are in agreement on the terms of the
17contract, then the Illinois Power Agency shall approve the
18contract. If after mediation the parties have failed to come to
19agreement, then the Illinois Power Agency shall revise the
20draft contract as necessary to confirm that the contract
21contains only terms that are reasonable and equitable. The
22Illinois Power Agency may, in its discretion, retain an
23independent, qualified, and experienced expert to assist in its
24obligations under this subsection (h). The Illinois Power
25Agency shall adopt and make public policies detailing the
26processes for retaining a mediator and an expert under this

 

 

09700SB2169ham001- 29 -LRB097 07925 ASK 55966 a

1subsection (h). Any mediator or expert retained under this
2subsection (h) shall be retained no later than 60 days after
3the effective date of this amendatory Act of the 97th General
4Assembly.
5    The Illinois Power Agency shall complete all of its
6responsibilities under this subsection (h) within 60 days after
7the effective date of this amendatory Act of the 97th General
8Assembly. The clean coal SNG facility shall pay a reasonable
9fee as required by the Illinois Power Agency for its services
10under this subsection (h) and shall pay the mediator's and
11expert's reasonable fees, if any. A gas utility and its
12customers shall have no obligation to reimburse the clean coal
13SNG facility or the Illinois Power Agency of any such costs.
14    Within 30 days after commercial production of SNG has
15begun, the Commission shall initiate a review to determine
16whether the final capitalized plant cost of the clean coal SNG
17facility reflects actual incurred costs and whether the
18incurred costs were reasonable. In determining the actual
19incurred costs included in the final capitalized plant cost and
20the reasonableness of those costs, the Commission may in its
21discretion retain independent, qualified, and experienced
22experts to assist in its determination. The expert shall not
23own or control any direct or indirect interest in the clean
24coal SNG facility and shall have no contractual relationship
25with the clean coal SNG facility. If an expert is retained by
26the Commission, then the clean coal SNG facility shall pay the

 

 

09700SB2169ham001- 30 -LRB097 07925 ASK 55966 a

1expert's reasonable fees. The fees shall not be passed on to a
2utility or its customers. The Commission shall adopt and make
3public a policy detailing the process for retaining experts
4under this subsection (h).
5    Within 30 days after completion of its review, the
6Commission shall initiate a formal proceeding on the final
7capitalized plant cost of the clean coal SNG facility at which
8comments and testimony may be submitted by any interested
9parties and the public. If the Commission finds that the final
10capitalized plant cost includes costs that were not actually
11incurred or costs that were unreasonably incurred, then the
12Commission shall disallow the amount of non-incurred or
13unreasonable costs from the SNG price under contracts entered
14into under this subsection (h). If the Commission disallows any
15costs, then the Commission shall adjust the SNG price using the
16price formula in the contract approved by the Illinois Power
17Agency under this subsection (h) to reflect the disallowed
18costs and shall enter an order specifying the revised price. In
19addition, the Commission's order shall direct the clean coal
20SNG facility to issue refunds of such sums as shall represent
21the difference between actual gross revenues and the gross
22revenue that would have been obtained based upon the same
23volume, from the price revised by the Commission. Any refund
24shall include interest calculated at a rate determined by the
25Commission and shall be returned according to procedures
26prescribed by the Commission.

 

 

09700SB2169ham001- 31 -LRB097 07925 ASK 55966 a

1    Nothing in this subsection (h) shall preclude any party
2affected by a decision of the Commission under this subsection
3(h) from seeking judicial review of the Commission's decision.
4    (h-5) All contracts entered into under subsection (h) of
5this Section, regardless of duration, shall require the owner
6of any facility supplying SNG under the contract to provide
7documentation to the Commission each year, starting in the
8facility's first year of commercial operation, accurately
9reporting the quantity of carbon dioxide emissions from the
10facility that have been captured and sequestered and reporting
11any quantities of carbon dioxide released from the site or
12sites at which carbon dioxide emissions were sequestered in
13prior years, based on continuous monitoring of those sites.
14    If, in any year, the owner of the clean coal SNG facility
15fails to demonstrate that the SNG facility captured and
16sequestered at least 90% of the total carbon dioxide emissions
17that the facility would otherwise emit or that sequestration of
18emissions from prior years has failed, resulting in the release
19of carbon dioxide into the atmosphere, then the owner of the
20clean coal SNG facility must pay a penalty of $20 per ton of
21excess carbon dioxide emissions not to exceed $40,000,000, in
22any given year which shall be deposited into the Energy
23Efficiency Trust Fund and distributed pursuant to the
24subsection (b) of Section 6-6 of the Renewable Energy, Energy
25Efficiency, and Coal Resources Development Law of 1997. On or
26before the 5-year anniversary of the execution of the contract

 

 

09700SB2169ham001- 32 -LRB097 07925 ASK 55966 a

1and every 5 years thereafter, an expert hired by the owner of
2the facility with the approval the Attorney General shall
3conduct an analysis to determine the cost of sequestration of
4at least 90% of the total carbon dioxide emissions the plant
5would otherwise emit. If the analysis shows that the actual
6annual cost is greater than the penalty, then the penalty shall
7be increased to equal the actual cost. Provided, however, to
8the extent that the owner of the facility described in
9subsection (h) of this Act can demonstrate that the failure was
10as a result of acts of God (including fire, flood, earthquake,
11tornado, lightning, hurricane, or other natural disaster); any
12amendment, modification, or abrogation of any applicable law or
13regulation that would prevent performance; war; invasion; act
14of foreign enemies; hostilities (regardless of whether war is
15declared); civil war; rebellion; revolution; insurrection;
16military or usurped power or confiscation; terrorist
17activities; civil disturbance; riots; nationalization;
18sabotage; blockage; or embargo, the owner of the facility
19described in subsection (h) of this Act shall not be subject to
20a penalty if and only if (i) it promptly provides notice of its
21failure to the Commission; (ii) as soon as practicable and
22consistent with any order or direction from the Commission, it
23submits to the Commission proposed modifications to its carbon
24capture and sequestration plan; and (iii) it carries out its
25proposed modifications in the manner and time directed by the
26Commission.

 

 

09700SB2169ham001- 33 -LRB097 07925 ASK 55966 a

1    If the Commission finds that the facility has not satisfied
2each of these requirements, then the facility shall be subject
3to the penalty. If the owner of the clean coal SNG facility
4captured and sequestered more than 90% of the total carbon
5emissions that the facility would otherwise emit, then the
6owner of the facility may credit such additional amounts to
7reduce the amount of any future penalty to be paid. The penalty
8resulting from the failure to capture and sequester at least
9the minimum amount of carbon dioxide shall not be passed on to
10a utility or its customers.
11    If the clean coal SNG facility fails to meet the
12requirements specified in this subsection (h-5), then the
13Attorney General, on behalf of the People of the State of
14Illinois, shall bring an action for specific performance of the
15obligations related to the facility set forth in this
16subsection (h-5), including any penalty payments owed, but not
17including the physical obligation to capture and sequester at
18lest 90% of the total carbon emissions that the facility would
19otherwise emit. Such action may be filed in any circuit court
20in Illinois. By entering into a contract pursuant to subsection
21(h) of this Section, the clean coal SNG facility agrees to
22waive any objections to venue or to the jurisdiction of the
23court with regard to the Attorney General's action for specific
24performance under this subsection (h-5).
25    Compliance with the sequestration requirements and any
26penalty requirements specified in this subsection (h-5) for the

 

 

09700SB2169ham001- 34 -LRB097 07925 ASK 55966 a

1clean coal SNG facility shall be assessed annually by the
2Commission, which may in its discretion retain an expert to
3facilitate its assessment. If any expert is retained by the
4Commission, then the clean coal SNG facility shall pay for the
5expert's reasonable fees, and such costs shall not be passed
6through to the utility or its customers.
7    In addition, carbon dioxide emission credits received by
8the clean coal SNG facility in connection with sequestration of
9carbon dioxide from the facility must be sold in a timely
10fashion with any revenue, less applicable fees and expenses and
11any expenses required to be paid by facility for carbon dioxide
12transportation or sequestration, deposited into the
13reconciliation account within 30 days after receipt of such
14funds by the owner of the clean coal SNG facility.
15    The clean coal SNG facility is prohibited from transporting
16or sequestering carbon dioxide unless the owner of the carbon
17dioxide pipeline that transfers the carbon dioxide from the
18facility and the owner of the sequestration site where the
19carbon dioxide captured by the facility is stored has acquired
20all applicable permits under applicable State and federal laws,
21statutes, rules, or regulations prior to the transfer or
22sequestration of carbon dioxide. The responsibility for
23compliance with the sequestration requirements specified in
24this subsection (h-5) for the clean coal SNG facility shall
25reside solely with the clean coal SNG facility, regardless of
26the whether the facility has contracted with another party to

 

 

09700SB2169ham001- 35 -LRB097 07925 ASK 55966 a

1capture, transport, or sequester carbon dioxide.
2    (h-7) Sequestration permitting, oversight, and
3investigations. No clean coal facility may transport or
4sequester carbon dioxide unless the Commission approves the
5method of carbon dioxide transportation or sequestration. Such
6approval shall be required regardless of whether the facility
7has contracted with another to transport or sequester the
8carbon dioxide. Nothing in this subsection (h-7) shall release
9the owner or operator of a carbon dioxide sequestration site or
10carbon dioxide pipeline from any other permitting requirements
11under applicable State and federal laws, statutes, rules, or
12regulations.
13    The Commission shall review carbon dioxide transportation
14and sequestration methods proposed by a clean coal facility and
15shall approve those methods it deems reasonable and
16cost-effective. For purposes of this review, "cost-effective"
17means a commercially reasonable price for similar carbon
18dioxide transportation or sequestration techniques. In
19determining whether sequestration is reasonable and
20cost-effective, the Commission may consult with the Illinois
21State Geological Survey and retain third parties to assist in
22its determination, provided that such third parties shall not
23own or control any direct or indirect interest in the facility
24that is proposing the carbon dioxide transportation or the
25carbon dioxide sequestration method and shall have no
26contractual relationship with that facility. If a third party

 

 

09700SB2169ham001- 36 -LRB097 07925 ASK 55966 a

1is retained by the Commission, then the facility proposing the
2carbon dioxide transportation or sequestration method shall
3pay for the expert's reasonable fees, and these costs shall not
4be passed through to a utility or its customers.
5    No later than 6 months prior to the date upon which the
6owner intends to commence construction of a clean coal facility
7the owner of the facility shall file with the Commission a
8carbon dioxide transportation or sequestration plan. The
9Commission shall hold a public hearing within 30 days after
10receipt of the facility's carbon dioxide transportation or
11sequestration plan. The Commission shall post notice of the
12review on its website upon submission of a carbon dioxide
13transportation or sequestration method and shall accept
14written public comments. The Commission shall take the comments
15into account when making its decision.
16    The Commission may not approve a carbon dioxide
17sequestration method if the owner or operator of the
18sequestration site has not received (i) an Underground
19Injection Control permit from the Illinois Environmental
20Protection Agency pursuant to the Environmental Protection
21Act; (ii) an Underground Injection Control permit from the
22Illinois Department of Natural Resources pursuant to the
23Illinois Oil and Gas Act; or (iii) a permit similar to items
24(i) or (ii) from the state in which the sequestration site is
25located if the sequestration will take place outside of
26Illinois. The Commission shall approve or deny the carbon

 

 

09700SB2169ham001- 37 -LRB097 07925 ASK 55966 a

1dioxide transportation or sequestration method within 90 days
2after the receipt of all required information.
3    At least annually, the Illinois Environmental Protection
4Agency shall inspect all carbon dioxide sequestration sites in
5Illinois. The Illinois Environmental Protection Agency may, as
6often as deemed necessary, monitor and conduct investigations
7of those sites. The owner or operator of the sequestration site
8must cooperate with the Illinois Environmental Protection
9Agency investigations of carbon dioxide sequestration sites.
10    If the Illinois Environmental Protection Agency determines
11at any time a site creates conditions that warrant the issuance
12of a seal order under Section 34 of the Environmental
13Protection Act, then the Illinois Environmental Protection
14Agency shall seal the site pursuant to the Environmental
15Protection Act. If the Illinois Environmental Protection
16Agency determines at any time a carbon dioxide sequestration
17site creates conditions that warrant the institution of a civil
18action for an injunction under Section 43 of the Environmental
19Protection Act, then the Illinois Environmental Protection
20Agency shall request the State's Attorney or the Attorney
21General institute such action. The Illinois Environmental
22Protection Agency shall provide notice of any such actions as
23soon as possible on its website. The facility shall incur all
24reasonable costs associated with any such inspection or
25monitoring of the sequestration sites, and these costs shall
26not be recoverable from utilities or their customers.

 

 

09700SB2169ham001- 38 -LRB097 07925 ASK 55966 a

1    At least annually, the Commission shall inspect all carbon
2dioxide pipelines in Illinois that transport carbon dioxide to
3ensure the safety and feasibility of those pipelines. The
4Commission may, as often as deemed necessary, monitor and
5conduct investigations of those pipelines. The owner or
6operator of the pipeline must cooperate with the Commission
7investigations of the carbon dioxide pipelines.
8    In circumstances whereby a carbon dioxide pipeline creates
9a substantial danger to the environment or to the public health
10of persons or to the welfare of persons where such danger is to
11the livelihood of such persons, the State's Attorney or
12Attorney General, upon the request of the Commission or on his
13or her own motion, may institute a civil action for an
14immediate injunction to halt any discharge or other activity
15causing or contributing to the danger or to require such other
16action as may be necessary. The court may issue an ex parte
17order and shall schedule a hearing on the matter not later than
183 working days after the date of injunction. The Commission
19shall provide notice of any such actions as soon as possible on
20its website. The SNG facility shall incur all reasonable costs
21associated with any such inspection or monitoring of the
22sequestration sites, and these costs shall not be recoverable
23from a utility or its customers.
24    (h-5) The Attorney General, on behalf of the people of the
25State of Illinois, may specifically enforce the requirements of
26this subsection (h-5). All contracts, regardless of duration,

 

 

09700SB2169ham001- 39 -LRB097 07925 ASK 55966 a

1shall require the owner of any facility supplying SNG under the
2contract to provide documentation to the Commission each year,
3starting in the facility's first year of commercial operation,
4accurately reporting the quantity of carbon dioxide emissions
5from the facility that have been captured and sequestered and
6reporting any quantities of carbon dioxide released from the
7site or sites at which carbon dioxide emissions were
8sequestered in prior years, based on continuous monitoring of
9those sites. If, in any year, the owner of the facility fails
10to demonstrate that the SNG facility captured and sequestered
11at least 90% of the total carbon dioxide emissions that the
12facility would otherwise emit or that sequestration of
13emissions from prior years has failed, resulting in the release
14of carbon dioxide into the atmosphere, then the owner of the
15facility must offset excess emissions. Any such carbon dioxide
16offsets must be permanent, additional, verifiable, real,
17located within the State of Illinois, and legally and
18practicably enforceable; provided that the owner of the
19facility shall not be obligated to acquire carbon dioxide
20emission offsets to the extent that the cost of acquiring such
21offsets would exceed $40 million in any given year. No costs of
22any purchases of carbon offsets may be recovered from a utility
23or its customers. All carbon offsets purchased for this purpose
24must be permanently retired. In addition, carbon dioxide
25emission credits equivalent to 50% of the amount of credits
26associated with the required sequestration of carbon dioxide

 

 

09700SB2169ham001- 40 -LRB097 07925 ASK 55966 a

1from the facility must be permanently retired. Compliance with
2the sequestration requirements and the offset purchase
3requirements specified in this subsection (h-5) shall be
4assessed annually by an independent expert retained by the
5owner of the SNG facility, with the advance written approval of
6the Attorney General. A SNG facility operating pursuant to this
7subsection (h-5) shall not forfeit its designation as a clean
8coal SNG facility if the facility fails to fully comply with
9the applicable carbon sequestration requirements in any given
10year, provided the requisite offsets are purchased.
11    (h-10) Contract costs for SNG incurred by an Illinois gas
12utility are reasonable and prudent and recoverable through the
13purchased gas adjustment clause and are not subject to review
14or disallowance by the Commission. Contract costs are costs
15incurred by the utility under the terms of a contract that
16incorporates the terms stated in subsection (h) of this Section
17as confirmed in writing by the Illinois Power Agency as set
18forth in subsection (h) (h-20) of this Section, which
19confirmation shall be deemed conclusive, or as a consequence of
20or condition to its performance under the contract, including
21(i) amounts paid for SNG under the SNG contract as adjusted for
22the clean coal SNG facility rider mechanism and (ii) costs of
23transportation and storage services of SNG purchased from
24interstate pipelines under federally approved tariffs. The
25clean coal SNG facility rider mechanism (A) shall be applicable
26to all customers who receive transportation service from the

 

 

09700SB2169ham001- 41 -LRB097 07925 ASK 55966 a

1utility, (B) shall be designed to have an equal percentage
2impact on the transportation services rates of each class of
3the utility's total customers, and (C) shall accurately reflect
4the net customer savings, if any, and above market costs, if
5any, under the SNG contract. Any contract, the terms of which
6have been confirmed in writing by the Illinois Power Agency as
7set forth in subsection (h) (h-20) of this Section and the
8performance of the parties under such contract cannot be
9grounds for challenging prudence or cost recovery by the
10utility through the purchased gas adjustment clause, and in
11such cases, the Commission is directed not to consider, and has
12no authority to consider, any attempted challenges.
13    The contracts entered into by Illinois gas utilities
14pursuant to subsection (h) of this Section shall provide that
15the utility retains the right to terminate the contract without
16further obligation or liability to any party if the contract
17has been impaired as a result of any legislative,
18administrative, judicial, or other governmental action that is
19taken that eliminates all or part of the prudence protection of
20this subsection (h-10) or denies the recoverability of all or
21part of the contract costs through the purchased gas adjustment
22clause. Should any Illinois gas utility exercise its right
23under this subsection (h-10) to terminate the contract, all
24contract costs incurred prior to termination are and will be
25deemed reasonable, prudent, and recoverable as and when
26incurred and not subject to review or disallowance by the

 

 

09700SB2169ham001- 42 -LRB097 07925 ASK 55966 a

1Commission. Any order, issued by the State requiring or
2authorizing the discontinuation of the merchant function,
3defined as the purchase and sale of natural gas by an Illinois
4gas utility for the ultimate consumer in its service territory
5shall include provisions necessary to prevent the impairment of
6the value of any contract hereunder over its full term.
7    (h-15) Reconciliation account. The clean coal SNG facility
8shall establish a reconciliation account for the benefit of the
9retail customers of the utilities that have entered into
10contracts with the clean coal SNG facility pursuant to
11subsection (h). The reconciliation account shall be maintained
12and administered by an independent trustee that is mutually
13agreed upon by the owners of the clean coal SNG facility, the
14utilities, and the Commission in an interest-bearing account in
15accordance with the following:
16        (1) The clean coal SNG facility shall conduct an
17    analysis annually within 60 days after receiving the
18    necessary cost information, which shall be provided by the
19    gas utility within 6 months after the end of the preceding
20    calendar year, to determine (i) the average annual contract
21    SNG cost, which shall be calculated as the total amount
22    paid for SNG purchased from the clean coal SNG facility
23    over the preceding 12 months, plus the cost to the utility
24    of the required transportation and storage services of SNG,
25    divided by the total number of MMBtus of SNG actually
26    purchased from the clean coal SNG facility in the preceding

 

 

09700SB2169ham001- 43 -LRB097 07925 ASK 55966 a

1    12 months under the utility contract; (ii) the average
2    annual natural gas purchase cost, which shall be calculated
3    as the total annual supply costs paid for natural gas
4    (excluding any SNG) purchased by such utility over the
5    preceding 12 months plus the costs of transportation and
6    storage services of such natural gas (excluding such costs
7    for SNG), divided by the total number of MMbtus of natural
8    gas (excluding SNG) actually purchased by the utility
9    during the year; (iii) the cost differential, which shall
10    be the difference between the average annual contract SNG
11    cost and the average annual natural gas purchase cost; and
12    (iv) the revenue share target which shall be the cost
13    differential multiplied by the total amount of SNG
14    purchased over the preceding 12 months under such utility
15    contract.
16            (A) To the extent the annual average contract SNG
17        cost is less than the annual average natural gas
18        purchase cost the utility shall credit an amount equal
19        to the revenue share target to the reconciliation
20        account. Such credit payment shall be made within 30
21        days after the completed analysis in this subsection
22        (h-15) and pursuant to this subparagraph (A) shall be
23        deemed prudent and reasonable and not subject to
24        Commission prudence review.
25            (B) To the extent the annual average contract SNG
26        cost is greater than the annual average natural gas

 

 

09700SB2169ham001- 44 -LRB097 07925 ASK 55966 a

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

 

 

09700SB2169ham001- 45 -LRB097 07925 ASK 55966 a

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

 

 

09700SB2169ham001- 46 -LRB097 07925 ASK 55966 a

1        (3) 50% of all additional net revenue, defined as
2    miscellaneous net revenue after cost allowance and above
3    the budgeted estimate established for revenue pursuant to
4    subsection (h), including sale of substitute natural gas
5    derived from the clean coal SNG facility above the
6    nameplate capacity of the facility and other by-products
7    produced by the facility, shall be credited to the
8    reconciliation account on an annual basis with such payment
9    made within 30 days after the end of each calendar year
10    during the term of the contract.
11        (4) The clean coal SNG facility shall each year,
12    starting in the facility's first year of commercial
13    operation, file with the Commission, in such form as the
14    Commission shall require, a report as to the reconciliation
15    account. The annual report must contain the following
16    information:
17            (A) the revenue share target amount;
18            (B) the amount credited or debited to the
19        reconciliation account during the year;
20            (C) the amount credited to the utilities to be used
21        to reduce the utilities natural gas costs though the
22        purchase gas adjustment clause;
23            (D) the total amount of reconciliation account at
24        the beginning and end of the year;
25            (E) the total amount of consumer saving to date;
26        and

 

 

09700SB2169ham001- 47 -LRB097 07925 ASK 55966 a

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

 

 

09700SB2169ham001- 48 -LRB097 07925 ASK 55966 a

1shall pay a penalty of $500 to the Commission for each day it
2is in default.
3    Any person who willfully makes any false report to the
4Commission or to any member, officer, or employee thereof, any
5person who willfully in a report withholds or fails to provide
6material information to which the Commission is entitled under
7this paragraph (4) and which information is either required to
8be filed by statute, rule, regulation, order, or decision of
9the Commission or has been requested by the Commission, and any
10person who willfully aids or abets such person shall be guilty
11of a Class A misdemeanor.
12    With respect to each contract entered into by the company
13with an Illinois utility in accordance with the terms stated in
14subsection (h) of this Section, within 60 days following the
15completion of purchases of SNG, the Illinois Power Agency shall
16conduct an analysis to determine (i) the average contract SNG
17cost, which shall be calculated as the total amount paid to a
18company for SNG over the contract term, plus the cost to the
19utility of the required transportation and storage services of
20SNG, divided by the total number of MMBtus of SNG actually
21purchased under the utility contract; (ii) the average natural
22gas purchase cost, which shall be calculated as the total
23annual supply costs paid for natural gas (excluding SNG)
24purchased by such utility over the contract term, plus the
25costs of transportation and storage services of such natural
26gas (excluding such costs for SNG), divided by the total number

 

 

09700SB2169ham001- 49 -LRB097 07925 ASK 55966 a

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

 

 

09700SB2169ham001- 50 -LRB097 07925 ASK 55966 a

1this Section, which constitute both "industrial projects"
2under Article 801 of the Illinois Finance Authority Act and
3"clean coal and energy projects" under Sections 825-65 through
4825-75 of the Illinois Finance Authority Act. The General
5Assembly further authorizes the Illinois Power Agency to become
6party to agreements and take such actions as necessary to
7enable the Illinois Power Agency or its designate to (i) review
8and confirm in writing that the terms stated in subsection (h)
9of this Section are incorporated in the SNG contract, and (ii)
10conduct an analysis pursuant to subsection (h-15) of this
11Section.
12    Administrative costs incurred by the Illinois Finance
13Authority and Illinois Power Agency in performance of this
14subsection (h-20) shall be subject to reimbursement by the
15clean coal SNG facility company on terms as the Illinois
16Finance Authority, the Illinois Power Agency, and the clean
17coal SNG facility company may agree. The utility and its
18customers shall have no obligation to reimburse the clean coal
19SNG facility or company, the Illinois Finance Authority, or the
20Illinois Power Agency for any such costs.
21    (h-25) The State of Illinois pledges that the State may not
22enact any law or take any action to (1) break or repeal the
23authority for SNG purchase contracts entered into between
24public gas utilities and the clean coal SNG facility pursuant
25to subsection (h) of this Section or (2) deny public gas
26utilities their full cost recovery for contract costs, as

 

 

09700SB2169ham001- 51 -LRB097 07925 ASK 55966 a

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

 

 

09700SB2169ham001- 52 -LRB097 07925 ASK 55966 a

1    (220 ILCS 20/2.02)  (from Ch. 111 2/3, par. 552.2)
2    Sec. 2.02.
3    "Gas" means natural gas, flammable gas or gas which is
4toxic or corrosive. "Gas" also means carbon dioxide in any
5physical form, whenever transported by pipeline for the purpose
6of sequestration.
7(Source: P.A. 76-1588.)
 
8    (220 ILCS 20/2.03)  (from Ch. 111 2/3, par. 552.3)
9    Sec. 2.03. "Transportation of gas" means the gathering,
10transmission, or distribution of gas by pipeline or its
11storage, within this State and not subject to the jurisdiction
12of the Federal Energy Regulatory Commission under the Natural
13Gas Act, except that it includes the transmission of gas
14through pipeline facilities within this State that transport
15gas from an interstate gas pipeline to a direct sales customer
16within this State purchasing gas for its own consumption.
17"Transportation of gas" also includes the conveyance of gas
18from a gas main through the primary fuel line to the outside
19wall of residential premises. If the gas meter is placed within
203 feet of the structure, the utility's responsibility shall end
21at the outlet side of the meter. "Transportation of gas" also
22includes the conveyance of carbon dioxide in any physical form
23for the purpose of sequestration.
24(Source: P.A. 87-1092; 88-314.)
 

 

 

09700SB2169ham001- 53 -LRB097 07925 ASK 55966 a

1    (220 ILCS 20/2.04)  (from Ch. 111 2/3, par. 552.4)
2    Sec. 2.04. "Pipeline facilities" includes new and existing
3pipe rights-of-way and any equipment, facility, or building
4used in the transportation of gas or the treatment of gas
5during the course of transportation and includes facilities
6within this State that transport gas from an interstate gas
7pipeline to a direct sales customer within this State
8purchasing gas for its own consumption, but "rights-of-way" as
9used in this Act does not authorize the Commission to
10prescribe, under this Act, the location or routing of any
11pipeline facility. "Pipeline facilities" also includes new and
12existing pipes and lines and any other equipment, facility, or
13structure, except customer-owned branch lines connected to the
14primary fuel lines, used to convey gas from a gas main to the
15outside wall of residential premises, and any person who
16provides gas service directly to its residential customer
17through these facilities shall be deemed to operate such
18pipeline facilities for purposes of this Act irrespective of
19the ownership of the facilities or the location of the
20facilities with respect to the meter, except that a person who
21provides gas service to a "master meter system", as that term
22is defined at 49 C.F.R. Section 191.3, shall not be deemed to
23operate any facilities downstream of the master meter.
24"Pipeline facilities" also includes new and existing pipe
25rights-of-way and any equipment, facility, or building used in
26the transportation of carbon dioxide in any physical form for

 

 

09700SB2169ham001- 54 -LRB097 07925 ASK 55966 a

1the purpose of sequestration.
2(Source: P.A. 87-1092; 88-314.)
 
3    (220 ILCS 20/3)  (from Ch. 111 2/3, par. 553)
4    Sec. 3. (a) As soon as practicable, but not later than 3
5months after the effective date of this Act, the Commission
6shall adopt rules establishing minimum safety standards for the
7transportation of gas and for pipeline facilities. Such rules
8shall be at least as inclusive, as stringent, and compatible
9with, the minimum safety standards adopted by the Secretary of
10Transportation under the Federal Act. Thereafter, the
11Commission shall maintain such rules so that the rules are at
12least as inclusive, as stringent, and compatible with, the
13minimum standards from time to time in effect under the Federal
14Act. The Commission shall also adopt rules establishing minimum
15safety standards for the transportation of carbon dioxide in
16any physical form for the purpose of sequestration and for
17pipeline facilities used for that function.
18    (b) Standards established under this Act may apply to the
19design, installation, inspection, testing, construction,
20extension, operation, replacement, and maintenance of pipeline
21facilities. Standards affecting the design, installation,
22construction, initial inspection and initial testing are not
23applicable to pipeline facilities in existence on the date such
24standards are adopted. Whenever the Commission finds a
25particular facility to be hazardous to life or property, it may

 

 

09700SB2169ham001- 55 -LRB097 07925 ASK 55966 a

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

 

 

09700SB2169ham001- 56 -LRB097 07925 ASK 55966 a

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

 

 

09700SB2169ham001- 57 -LRB097 07925 ASK 55966 a

1Inspection Fund established under Section 22.8 of this Act. The
2Agency may adopt rules relating to the collection of costs due
3under this subsection (d).
4    (e) The Agency shall not issue a permit or permit
5modification for the underground injection of carbon dioxide
6unless all costs for which the permitee is liable under
7subsection (d) of this Section have been paid.
8    (f) No person shall fail or refuse to pay costs for which
9the person is liable under subsection (d) of this Section.
 
10    Section 97. Inseverability. The provisions of this Act are
11mutually dependent and inseverable. If any provision is held
12invalid, then this entire Act, including all new and amendatory
13provisions, is invalid.
 
14    Section 99. Effective date. This Act takes effect upon
15becoming law.".