98TH GENERAL ASSEMBLY
State of Illinois
2013 and 2014
HB2414

 

Introduced , by Rep. Brandon W. Phelps

 

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

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


LRB098 07848 JLS 37932 b

FISCAL NOTE ACT MAY APPLY

 

 

A BILL FOR

 

HB2414LRB098 07848 JLS 37932 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 Public Utilities Act is amended by changing
5Section 9-220 and by adding Sections 9-244.5 and 19-150.6 as
6follows:
 
7    (220 ILCS 5/9-220)  (from Ch. 111 2/3, par. 9-220)
8    Sec. 9-220. Rate changes based on changes in fuel costs.
9    (a) Notwithstanding the provisions of Section 9-201, the
10Commission may authorize the increase or decrease of rates and
11charges based upon changes in the cost of fuel used in the
12generation or production of electric power, changes in the cost
13of purchased power, or changes in the cost of purchased gas
14through the application of fuel adjustment clauses or purchased
15gas adjustment clauses. The Commission may also authorize the
16increase or decrease of rates and charges based upon
17expenditures or revenues resulting from the purchase or sale of
18emission allowances created under the federal Clean Air Act
19Amendments of 1990, through such fuel adjustment clauses, as a
20cost of fuel. For the purposes of this paragraph, cost of fuel
21used in the generation or production of electric power shall
22include the amount of any fees paid by the utility for the
23implementation and operation of a process for the

 

 

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1desulfurization of the flue gas when burning high sulfur coal
2at any location within the State of Illinois irrespective of
3the attainment status designation of such location; but shall
4not include transportation costs of coal (i) except to the
5extent that for contracts entered into on and after the
6effective date of this amendatory Act of 1997, the cost of the
7coal, including transportation costs, constitutes the lowest
8cost for adequate and reliable fuel supply reasonably available
9to the public utility in comparison to the cost, including
10transportation costs, of other adequate and reliable sources of
11fuel supply reasonably available to the public utility, or (ii)
12except as otherwise provided in the next 3 sentences of this
13paragraph. Such costs of fuel shall, when requested by a
14utility or at the conclusion of the utility's next general
15electric rate proceeding, whichever shall first occur, include
16transportation costs of coal purchased under existing coal
17purchase contracts. For purposes of this paragraph "existing
18coal purchase contracts" means contracts for the purchase of
19coal in effect on the effective date of this amendatory Act of
201991, as such contracts may thereafter be amended, but only to
21the extent that any such amendment does not increase the
22aggregate quantity of coal to be purchased under such contract.
23Nothing herein shall authorize an electric utility to recover
24through its fuel adjustment clause any amounts of
25transportation costs of coal that were included in the revenue
26requirement used to set base rates in its most recent general

 

 

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1rate proceeding. Cost shall be based upon uniformly applied
2accounting principles. Annually, the Commission shall initiate
3public hearings to determine whether the clauses reflect actual
4costs of fuel, gas, power, or coal transportation purchased to
5determine whether such purchases were prudent, and to reconcile
6any amounts collected with the actual costs of fuel, power,
7gas, or coal transportation prudently purchased. In each such
8proceeding, the burden of proof shall be upon the utility to
9establish the prudence of its cost of fuel, power, gas, or coal
10transportation purchases and costs. The Commission shall issue
11its final order in each such annual proceeding for an electric
12utility by December 31 of the year immediately following the
13year to which the proceeding pertains, provided, that the
14Commission shall issue its final order with respect to such
15annual proceeding for the years 1996 and earlier by December
1631, 1998.
17    (b) A public utility providing electric service, other than
18a public utility described in subsections (e) or (f) of this
19Section, may at any time during the mandatory transition period
20file with the Commission proposed tariff sheets that eliminate
21the public utility's fuel adjustment clause and adjust the
22public utility's base rate tariffs by the amount necessary for
23the base fuel component of the base rates to recover the public
24utility's average fuel and power supply costs per kilowatt-hour
25for the 2 most recent years for which the Commission has issued
26final orders in annual proceedings pursuant to subsection (a),

 

 

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

 

 

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

 

 

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

 

 

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1projected jurisdictional power supply costs or gas supply costs
2for a future 12 month period conforming to (ii) above. If the
3Commission's order requires modifications in the tariff sheets
4filed by the public utility, the public utility shall have 7
5days following the date of the order to notify the Commission
6whether the public utility will implement the modified tariffs
7or elect to continue its fuel or purchased gas adjustment
8clause in force as though no order had been entered. The
9Commission's order shall provide for any reconciliation of
10power supply costs or gas supply costs, as the case may be, and
11associated revenues through the date that the public utility's
12fuel or purchased gas adjustment clause is eliminated. During
13the 5 years following the date of the Commission's order, a
14public utility whose fuel or purchased gas adjustment clause
15has been eliminated pursuant to this subsection shall not file
16proposed tariff sheets seeking, or otherwise petition the
17Commission for, reinstatement or adoption of a fuel or
18purchased gas adjustment clause. Nothing in this subsection (d)
19shall be construed as limiting the Commission's authority to
20eliminate a public utility's fuel adjustment clause or
21purchased gas adjustment clause in accordance with any other
22applicable provisions of this Act.
23    (e) Notwithstanding any contrary or inconsistent
24provisions in Section 9-201 of this Act, in subsection (a) of
25this Section, or in any rules promulgated by the Commission
26pursuant to subsection (g) of this Section, a public utility

 

 

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1providing electric service to more than 1,000,000 customers in
2this State may, within the first 6 months after the effective
3date of this amendatory Act of 1997, file with the Commission
4proposed tariff sheets that eliminate, effective January 1,
51997, the public utility's fuel adjustment clause without
6adjusting its base rates, and such tariff sheets shall be
7effective upon filing. To the extent the application of the
8fuel adjustment clause had resulted in net charges to customers
9after January 1, 1997, the utility shall also file a tariff
10sheet that provides for a refund stated on a per kilowatt-hour
11basis of such charges over a period not to exceed 6 months;
12provided however, that such refund shall not include the
13proportional amounts of taxes paid under the Use Tax Act,
14Service Use Tax Act, Service Occupation Tax Act, and Retailers'
15Occupation Tax Act on fuel used in generation. The Commission
16shall issue an order within 45 days after the date of the
17public utility's filing approving or approving as modified such
18tariff sheet. If the fuel adjustment clause is eliminated
19pursuant to this subsection, the Commission shall not conduct
20the annual hearings specified in the last 3 sentences of
21subsection (a) of this Section for the utility for any period
22after December 31, 1996 and prior to any reinstatement of such
23clause. A public utility whose fuel adjustment clause has been
24eliminated pursuant to this subsection shall not file a
25proposed tariff sheet seeking, or otherwise petition the
26Commission for, reinstatement of the fuel adjustment clause

 

 

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1prior to January 1, 2007.
2    (f) Notwithstanding any contrary or inconsistent
3provisions in Section 9-201 of this Act, in subsection (a) of
4this Section, or in any rules or regulations promulgated by the
5Commission pursuant to subsection (g) of this Section, a public
6utility providing electric service to more than 500,000
7customers but fewer than 1,000,000 customers in this State may,
8within the first 6 months after the effective date of this
9amendatory Act of 1997, file with the Commission proposed
10tariff sheets that eliminate, effective January 1, 1997, the
11public utility's fuel adjustment clause and adjust its base
12rates by the amount necessary for the base fuel component of
13the base rates to recover 91% of the public utility's average
14fuel and power supply costs for the 2 most recent years for
15which the Commission, as of January 1, 1997, has issued final
16orders in annual proceedings pursuant to subsection (a), where
17the average fuel and power supply costs per kilowatt-hour shall
18be calculated as the sum of the public utility's prudent and
19allowable fuel and power supply costs as found by the
20Commission in the 2 proceedings divided by the public utility's
21actual jurisdictional kilowatt-hour sales for those 2 years,
22provided, that such tariff sheets shall be effective upon
23filing. To the extent the application of the fuel adjustment
24clause had resulted in net charges to customers after January
251, 1997, the utility shall also file a tariff sheet that
26provides for a refund stated on a per kilowatt-hour basis of

 

 

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1such charges over a period not to exceed 6 months. Provided
2however, that such refund shall not include the proportional
3amounts of taxes paid under the Use Tax Act, Service Use Tax
4Act, Service Occupation Tax Act, and Retailers' Occupation Tax
5Act on fuel used in generation. The Commission shall issue an
6order within 45 days after the date of the public utility's
7filing approving or approving as modified such tariff sheet. If
8the fuel adjustment clause is eliminated pursuant to this
9subsection, the Commission shall not conduct the annual
10hearings specified in the last 3 sentences of subsection (a) of
11this Section for the utility for any period after December 31,
121996 and prior to any reinstatement of such clause. A public
13utility whose fuel adjustment clause has been eliminated
14pursuant to this subsection shall not file a proposed tariff
15sheet seeking, or otherwise petition the Commission for,
16reinstatement of the fuel adjustment clause prior to January 1,
172007.
18    (g) The Commission shall have authority to promulgate rules
19and regulations to carry out the provisions of this Section.
20    (h) Any Illinois gas utility may enter into a contract on
21or before September 30, 2011 for up to 10 years of supply with
22any company for the purchase of substitute natural gas (SNG)
23produced from coal through the gasification process if the
24company has commenced construction of a clean coal SNG facility
25by July 1, 2012 and commencement of construction shall mean
26that material physical site work has occurred, such as site

 

 

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1clearing and excavation, water runoff prevention, water
2retention reservoir preparation, or foundation development.
3The contract shall contain the following provisions: (i) at
4least 90% of feedstock to be used in the gasification process
5shall be coal with a high volatile bituminous rank and greater
6than 1.7 pounds of sulfur per million Btu content; (ii) at the
7time the contract term commences, the price per million Btu may
8not exceed $7.95 in 2008 dollars, adjusted annually based on
9the change in the Annual Consumer Price Index for All Urban
10Consumers for the Midwest Region as published in April by the
11United States Department of Labor, Bureau of Labor Statistics
12(or a suitable Consumer Price Index calculation if this
13Consumer Price Index is not available) for the previous
14calendar year; provided that the price per million Btu shall
15not exceed $9.95 at any time during the contract; (iii) the
16utility's supply contract for the purchase of SNG does not
17exceed 15% of the annual system supply requirements of the
18utility as of 2008; and (iv) the contract costs pursuant to
19subsection (h-10) of this Section shall not include any
20lobbying expenses, charitable contributions, advertising,
21organizational memberships, carbon dioxide pipeline or
22sequestration expenses, or marketing expenses.
23    Any gas utility that is providing service to more than
24150,000 customers on August 2, 2011 (the effective date of
25Public Act 97-239) shall either elect to enter into a contract
26on or before September 30, 2011 for 10 years of SNG supply with

 

 

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1the owner of a clean coal SNG facility or to file biennial rate
2proceedings before the Commission in the years 2012, 2014, and
32016, with such filings made after August 2, 2011 and no later
4than September 30 of the years 2012, 2014, and 2016 consistent
5with all requirements of 83 Ill. Adm. Code 255 and 285 as
6though the gas utility were filing for an increase in its
7rates, without regard to whether such filing would produce an
8increase, a decrease, or no change in the gas utility's rates,
9and the Commission shall review the gas utility's filing and
10shall issue its order in accordance with the provisions of
11Section 9-201 of this Act; provided, however, that a gas
12utility having performance-based rates in effect pursuant to
13Section 9-244.5 of this Act that previously elected to make
14rate filings under this Section shall have no obligation to
15make such filings while such performance-based rates are in
16effect and the gas utility may withdraw, and the Commission
17shall approve any such request to withdraw, any pending rate
18filing at any time after it files to implement
19performance-based rates pursuant to Section 9-244.5.
20    Within 7 days after August 2, 2011, the owner of the clean
21coal SNG facility shall submit to the Illinois Power Agency and
22each gas utility that is providing service to more than 150,000
23customers on August 2, 2011 a copy of a draft contract. Within
2430 days after the receipt of the draft contract, each such gas
25utility shall provide the Illinois Power Agency and the owner
26of the clean coal SNG facility with its comments and

 

 

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

 

 

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1    ensure that it meets the requirements of this subsection
2    (h);
3        (3) review and approve the amount of budgeted
4    miscellaneous net revenue after cost allowance, including
5    sale of SNG produced by the clean coal SNG facility above
6    the nameplate capacity of the facility and other
7    by-products produced by the facility, to be included in the
8    pricing formula; the Illinois Power Agency shall approve
9    the amount of budgeted miscellaneous net revenue to be
10    included in the pricing formula if it determines the
11    budgeted amount to be reasonable and accurate;
12        (4) review and confirm in writing that using the EIA
13    Annual Energy Outlook-2011 Henry Hub Spot Price, the
14    contract terms set out in subsection (h), the
15    reconciliation account terms as set out in subsection
16    (h-15), and an estimated inflation rate of 2.5% for each
17    corresponding year, that there will be no cumulative
18    estimated increase for residential customers; and
19        (5) allocate the nameplate capacity of the clean coal
20    SNG by total therms sold to ultimate customers by each gas
21    utility in 2008; provided, however, no utility shall be
22    required to purchase more than 42% of the projected annual
23    output of the facility; additionally, the Illinois Power
24    Agency shall further adjust the allocation only as required
25    to take into account (A) adverse consolidation,
26    derivative, or lease impacts to the balance sheet or income

 

 

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1    statement of any gas utility or (B) the physical capacity
2    of the gas utility to accept SNG.
3    If the parties to the contract do not agree on the terms
4therein, then the Illinois Power Agency shall retain an
5independent mediator to mediate the dispute between the
6parties. If the parties are in agreement on the terms of the
7contract, then the Illinois Power Agency shall approve the
8contract. If after mediation the parties have failed to come to
9agreement, then the Illinois Power Agency shall revise the
10draft contract as necessary to confirm that the contract
11contains only terms that are reasonable and equitable. The
12Illinois Power Agency may, in its discretion, retain an
13independent, qualified, and experienced expert to assist in its
14obligations under this subsection (h). The Illinois Power
15Agency shall adopt and make public policies detailing the
16processes for retaining a mediator and an expert under this
17subsection (h). Any mediator or expert retained under this
18subsection (h) shall be retained no later than 60 days after
19August 2, 2011.
20    The Illinois Power Agency shall complete all of its
21responsibilities under this subsection (h) within 60 days after
22August 2, 2011. The clean coal SNG facility shall pay a
23reasonable fee as required by the Illinois Power Agency for its
24services under this subsection (h) and shall pay the mediator's
25and expert's reasonable fees, if any. A gas utility and its
26customers shall have no obligation to reimburse the clean coal

 

 

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

 

 

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1unreasonable costs from the SNG price under contracts entered
2into under this subsection (h). If the Commission disallows any
3costs, then the Commission shall adjust the SNG price using the
4price formula in the contract approved by the Illinois Power
5Agency under this subsection (h) to reflect the disallowed
6costs and shall enter an order specifying the revised price. In
7addition, the Commission's order shall direct the clean coal
8SNG facility to issue refunds of such sums as shall represent
9the difference between actual gross revenues and the gross
10revenue that would have been obtained based upon the same
11volume, from the price revised by the Commission. Any refund
12shall include interest calculated at a rate determined by the
13Commission and shall be returned according to procedures
14prescribed by the Commission.
15    Nothing in this subsection (h) shall preclude any party
16affected by a decision of the Commission under this subsection
17(h) from seeking judicial review of the Commission's decision.
18    (h-1) Any Illinois gas utility may enter into a sourcing
19agreement for up to 30 years of supply with the clean coal SNG
20brownfield facility if the clean coal SNG brownfield facility
21has commenced construction. Any gas utility that is providing
22service to more than 150,000 customers on July 13, 2011 (the
23effective date of Public Act 97-096) shall either elect to file
24biennial rate proceedings before the Commission in the years
252012, 2014, and 2016 or enter into a sourcing agreement or
26sourcing agreements with a clean coal SNG brownfield facility

 

 

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1with an initial term of 30 years for either (i) a percentage of
243,500,000,000 cubic feet per year, such that the utilities
3entering into sourcing agreements with the clean coal SNG
4brownfield facility purchase 100%, allocated by total therms
5sold to ultimate customers by each gas utility in 2008 or (ii)
6such lesser amount as may be available from the clean coal SNG
7brownfield facility; provided that no utility shall be required
8to purchase more than 42% of the projected annual output of the
9clean coal SNG brownfield facility, with the remainder of such
10utility's obligation to be divided proportionately between the
11other utilities, and provided that the Illinois Power Agency
12shall further adjust the allocation only as required to take
13into account adverse consolidation, derivative, or lease
14impacts to the balance sheet or income statement of any gas
15utility.
16    A gas utility electing to file biennial rate proceedings
17before the Commission must file a notice of its election with
18the Commission within 60 days after July 13, 2011 or its right
19to make the election is irrevocably waived. A gas utility
20electing to file biennial rate proceedings shall make such
21filings no later than August 1 of the years 2012, 2014, and
222016, consistent with all requirements of 83 Ill. Adm. Code 255
23and 285 as though the gas utility were filing for an increase
24in its rates, without regard to whether such filing would
25produce an increase, a decrease, or no change in the gas
26utility's rates, and notwithstanding any other provisions of

 

 

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1this Act, the Commission shall fully review the gas utility's
2filing and shall issue its order in accordance with the
3provisions of Section 9-201 of this Act, provided, however,
4that a gas utility having performance-based rates in effect
5pursuant to Section 9-244.5 of this Act that previously elected
6to make rate filings under this Section shall have no
7obligation to make such filings while such performance-based
8rates are in effect and the gas utility may withdraw, and the
9Commission shall approve any such request to withdraw, any
10pending rate filing at any time after it files to implement
11performance-based rates pursuant to Section 9-244.5 regardless
12of whether the Commission has approved a formula rate for the
13gas utility.
14    Within 15 days after July 13, 2011, the owner of the clean
15coal SNG brownfield facility shall submit to the Illinois Power
16Agency and each gas utility that is providing service to more
17than 150,000 customers on July 13, 2011 a copy of a draft
18sourcing agreement. Within 45 days after receipt of the draft
19sourcing agreement, each such gas utility shall provide the
20Illinois Power Agency and the owner of a clean coal SNG
21brownfield facility with its comments and recommended
22revisions to the draft sourcing agreement. Within 15 days after
23the receipt of the gas utility's comments and recommended
24revisions, the owner of the clean coal SNG brownfield facility
25shall submit its responsive comments and a further revised
26draft of the sourcing agreement to the Illinois Power Agency.

 

 

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1The Illinois Power Agency shall review the draft sourcing
2agreement and comments.
3    If the parties to the sourcing agreement do not agree on
4the terms therein, then the Illinois Power Agency shall retain
5an independent mediator to mediate the dispute between the
6parties. If the parties are in agreement on the terms of the
7sourcing agreement, the Illinois Power Agency shall approve the
8final draft sourcing agreement. If after mediation the parties
9have failed to come to agreement, then the Illinois Power
10Agency shall revise the draft sourcing agreement as necessary
11to confirm that the final draft sourcing agreement contains
12only terms that are reasonable and equitable. The Illinois
13Power Agency shall adopt and make public a policy detailing the
14process for retaining a mediator under this subsection (h-1).
15Any mediator retained to assist with mediating disputes between
16the parties regarding the sourcing agreement shall be retained
17no later than 60 days after July 13, 2011.
18    Upon approval of a final draft agreement, the Illinois
19Power Agency shall submit the final draft agreement to the
20Capital Development Board and the Commission no later than 90
21days after July 13, 2011. The gas utility and the clean coal
22SNG brownfield facility shall pay a reasonable fee as required
23by the Illinois Power Agency for its services under this
24subsection (h-1) and shall pay the mediator's reasonable fees,
25if any. The Illinois Power Agency shall adopt and make public a
26policy detailing the process for retaining a mediator under

 

 

HB2414- 21 -LRB098 07848 JLS 37932 b

1this Section.
2    The sourcing agreement between a gas utility and the clean
3coal SNG brownfield facility shall contain the following
4provisions:
5        (1) Any and all coal used in the gasification process
6    must be coal that has high volatile bituminous rank and
7    greater than 1.7 pounds of sulfur per million Btu content.
8        (2) Coal and petroleum coke are feedstocks for the
9    gasification process, with coal comprising at least 50% of
10    the total feedstock over the term of the sourcing agreement
11    unless the facility reasonably determines that it is
12    necessary to use additional petroleum coke to deliver net
13    consumer savings, in which case the facility shall use coal
14    for at least 35% of the total feedstock over the term of
15    any sourcing agreement and with the feedstocks to be
16    procured in accordance with requirements of Section 1-78 of
17    the Illinois Power Agency Act.
18        (3) The sourcing agreement has an initial term that
19    once entered into terminates no more than 30 years after
20    the commencement of the commercial production of SNG at the
21    clean coal SNG brownfield facility.
22        (4) The clean coal SNG brownfield facility guarantees a
23    minimum of $100,000,000 in consumer savings to customers of
24    the utilities that have entered into sourcing agreements
25    with the clean coal SNG brownfield facility, calculated in
26    real 2010 dollars at the conclusion of the term of the

 

 

HB2414- 22 -LRB098 07848 JLS 37932 b

1    sourcing agreement by comparing the delivered SNG price to
2    the Chicago City-gate price on a weighted daily basis for
3    each day over the entire term of the sourcing agreement, to
4    be provided in accordance with subsection (h-2) of this
5    Section.
6        (5) Prior to the clean coal SNG brownfield facility
7    issuing a notice to proceed to construction, the clean coal
8    SNG brownfield facility shall establish a consumer
9    protection reserve account for the benefit of the customers
10    of the utilities that have entered into sourcing agreements
11    with the clean coal SNG brownfield facility pursuant to
12    this subsection (h-1), with cash principal in the amount of
13    $150,000,000. This cash principal shall only be
14    recoverable through the consumer protection reserve
15    account and not as a cost to be recovered in the delivered
16    SNG price pursuant to subsection (h-3) of this Section. The
17    consumer protection reserve account shall be maintained
18    and administered by an independent trustee that is mutually
19    agreed upon by the clean coal SNG brownfield facility, the
20    utilities, and the Commission in an interest-bearing
21    account in accordance with subsection (h-2) of this
22    Section.
23        "Consumer protection reserve account principal maximum
24    amount" shall mean the maximum amount of principal to be
25    maintained in the consumer protection reserve account.
26    During the first 2 years of operation of the facility,

 

 

HB2414- 23 -LRB098 07848 JLS 37932 b

1    there shall be no consumer protection reserve account
2    maximum amount. After the first 2 years of operation of the
3    facility, the consumer protection reserve account maximum
4    amount shall be $150,000,000. After 5 years of operation,
5    and every 5 years thereafter, the trustee shall calculate
6    the 5-year average balance of the consumer protection
7    reserve account. If the trustee determines that during the
8    prior 5 years the consumer protection reserve account has
9    had an average account balance of less than $75,000,000,
10    then the consumer protection reserve account principal
11    maximum amount shall be increased by $5,000,000. If the
12    trustee determines that during the prior 5 years the
13    consumer protection reserve account has had an average
14    account balance of more than $75,000,000, then the consumer
15    protection reserve account principal maximum amount shall
16    be decreased by $5,000,000.
17        (6) The clean coal SNG brownfield facility shall
18    identify and sell economically viable by-products produced
19    by the facility.
20        (7) Fifty percent of all additional net revenue,
21    defined as miscellaneous net revenue from products
22    produced by the facility and delivered during the month
23    after cost allowance for costs associated with additional
24    net revenue that are not otherwise recoverable pursuant to
25    subsection (h-3) of this Section, including net revenue
26    from sales of substitute natural gas derived from the

 

 

HB2414- 24 -LRB098 07848 JLS 37932 b

1    facility above the nameplate capacity of the facility and
2    other by-products produced by the facility, shall be
3    credited to the consumer protection reserve account
4    pursuant to subsection (h-2) of this Section.
5        (8) The delivered SNG price per million btu to be paid
6    monthly by the utility to the clean coal SNG brownfield
7    facility, which shall be based only upon the following: (A)
8    a capital recovery charge, operations and maintenance
9    costs, and sequestration costs, only to the extent approved
10    by the Commission pursuant to paragraphs (1), (2), and (3)
11    of subsection (h-3) of this Section; (B) the actual
12    delivered and processed fuel costs pursuant to paragraph
13    (4) of subsection (h-3) of this Section; (C) actual costs
14    of SNG transportation pursuant to paragraph (6) of
15    subsection (h-3) of this Section; (D) certain taxes and
16    fees imposed by the federal government, the State, or any
17    unit of local government as provided in paragraph (6) of
18    subsection (h-3) of this Section; and (E) the credit, if
19    any, from the consumer protection reserve account pursuant
20    to subsection (h-2) of this Section. The delivered SNG
21    price per million Btu shall proportionately reflect these
22    elements over the term of the sourcing agreement.
23        (9) A formula to translate the recoverable costs and
24    charges under subsection (h-3) of this Section into the
25    delivered SNG price per million btu.
26        (10) Title to the SNG shall pass at a mutually

 

 

HB2414- 25 -LRB098 07848 JLS 37932 b

1    agreeable point in Illinois, and may provide that, rather
2    than the utility taking title to the SNG, a mutually agreed
3    upon third-party gas marketer pursuant to a contract
4    approved by the Illinois Power Agency or its designee may
5    take title to the SNG pursuant to an agreement between the
6    utility, the owner of the clean coal SNG brownfield
7    facility, and the third-party gas marketer.
8        (11) A utility may exit the sourcing agreement without
9    penalty if the clean coal SNG brownfield facility does not
10    commence construction by July 1, 2015.
11        (12) A utility is responsible to pay only the
12    Commission determined unit price cost of SNG that is
13    purchased by the utility. Nothing in the sourcing agreement
14    will obligate a utility to invest capital in a clean coal
15    SNG brownfield facility.
16        (13) The quality of SNG must, at a minimum, be
17    equivalent to the quality required for interstate pipeline
18    gas before a utility is required to accept and pay for SNG
19    gas.
20        (14) Nothing in the sourcing agreement will require a
21    utility to construct any facilities to accept delivery of
22    SNG. Provided, however, if a utility is required by law or
23    otherwise elects to connect the clean coal SNG brownfield
24    facility to an interstate pipeline, then the utility shall
25    be entitled to recover pursuant to its tariffs all just and
26    reasonable costs that are prudently incurred. Any costs

 

 

HB2414- 26 -LRB098 07848 JLS 37932 b

1    incurred by the utility to receive, deliver, manage, or
2    otherwise accommodate purchases under the SNG sourcing
3    agreement will be fully recoverable through a utility's
4    purchased gas adjustment clause rider mechanism in
5    conjunction with a SNG brownfield facility rider
6    mechanism. The SNG brownfield facility rider mechanism (A)
7    shall be applicable to all customers who receive
8    transportation service from the utility, (B) shall be
9    designed to have an equal percent impact on the
10    transportation services rates of each class of the
11    utility's customers, and (C) shall accurately reflect the
12    net consumer savings, if any, and above-market costs, if
13    any, associated with the utility receiving, delivering,
14    managing, or otherwise accommodating purchases under the
15    SNG sourcing agreement.
16        (15) Remedies for the clean coal SNG brownfield
17    facility's failure to deliver a designated amount for a
18    designated period.
19        (16) The clean coal SNG brownfield facility shall make
20    a good faith effort to ensure that an amount equal to not
21    less than 15% of the value of its prime construction
22    contract for the facility shall be established as a goal to
23    be awarded to minority owned businesses, female owned
24    businesses, and businesses owned by a person with a
25    disability; provided that at least 75% of the amount of
26    such total goal shall be for minority owned businesses.

 

 

HB2414- 27 -LRB098 07848 JLS 37932 b

1    "Minority owned business", "female owned business", and
2    "business owned by a person with a disability" shall have
3    the meanings ascribed to them in Section 2 of the Business
4    Enterprise for Minorities, Females and Persons with
5    Disabilities Act.
6        (17) Prior to the clean coal SNG brownfield facility
7    issuing a notice to proceed to construction, the clean coal
8    SNG brownfield facility shall file with the Commission a
9    certificate from an independent engineer that the clean
10    coal SNG brownfield facility has (A) obtained all
11    applicable State and federal environmental permits
12    required for construction; (B) obtained approval from the
13    Commission of a carbon capture and sequestration plan; and
14    (C) obtained all necessary permits required for
15    construction for the transportation and sequestration of
16    carbon dioxide as set forth in the Commission-approved
17    carbon capture and sequestration plan.
18    (h-2) Consumer protection reserve account. The clean coal
19SNG brownfield facility shall guarantee a minimum of
20$100,000,000 in consumer savings to customers of the utilities
21that have entered into sourcing agreements with the clean coal
22SNG brownfield facility, calculated in real 2010 dollars at the
23conclusion of the term of the sourcing agreement by comparing
24the delivered SNG price to the Chicago City-gate price on a
25weighted daily basis for each day over the entire term of the
26sourcing agreement. Prior to the clean coal SNG brownfield

 

 

HB2414- 28 -LRB098 07848 JLS 37932 b

1facility issuing a notice to proceed to construction, the clean
2coal SNG brownfield facility shall establish a consumer
3protection reserve account for the benefit of the retail
4customers of the utilities that have entered into sourcing
5agreements with the clean coal SNG brownfield facility pursuant
6to subsection (h-1), with cash principal in the amount of
7$150,000,000. Such cash principal shall only be recovered
8through the consumer protection reserve account and not as a
9cost to be recovered in the delivered SNG price pursuant to
10subsection (h-3) of this Section. The consumer protection
11reserve account shall be maintained and administered by an
12independent trustee that is mutually agreed upon by the clean
13coal SNG brownfield facility, the utilities, and the Commission
14in an interest-bearing account in accordance with the
15following:
16        (1) The clean coal SNG brownfield facility monthly
17    shall calculate (A) the difference between the monthly
18    delivered SNG price and the Chicago City-gate price, by
19    comparing the delivered SNG price, which shall include the
20    cost of transportation to the delivery point, if any, to
21    the Chicago City-gate price on a weighted daily basis for
22    each day of the prior month based upon a mutually agreed
23    upon published index and (B) the overage amount, if any, by
24    calculating the annualized incremental additional cost, if
25    any, of the delivered SNG in excess of 2.015% of the
26    average annual inflation-adjusted amounts paid by all gas

 

 

HB2414- 29 -LRB098 07848 JLS 37932 b

1    distribution customers in connection with natural gas
2    service during the 5 years ending May 31, 2010.
3        (2) During the first 2 years of operation of the
4    facility:
5            (A) to the extent there is an overage amount, the
6        consumer protection reserve account shall be used to
7        provide a credit to reduce the SNG price by an amount
8        equal to the overage amount; and
9            (B) to the extent the monthly delivered SNG price
10        is less than or equal to the Chicago City-gate price,
11        the utility shall credit the difference between the
12        monthly delivered SNG price and the monthly Chicago
13        City-gate price, if any, to the consumer protection
14        reserve account. Such credit issued pursuant to this
15        paragraph (B) shall be deemed prudent and reasonable
16        and not subject to a Commission prudence review;
17        (3) After 2 years of operation of the facility, and
18    monthly, on an on-going basis, thereafter:
19            (A) to the extent that the monthly delivered SNG
20        price is less than or equal to the Chicago City-gate
21        price, calculated using the weighted average of the
22        daily Chicago City-gate price on a daily basis over the
23        entire month, the utility shall credit the difference,
24        if any, to the consumer protection reserve account.
25        Such credit issued pursuant to this subparagraph (A)
26        shall be deemed prudent and reasonable and not subject

 

 

HB2414- 30 -LRB098 07848 JLS 37932 b

1        to a Commission prudence review;
2            (B) any amounts in the consumer protection reserve
3        account in excess of the consumer protection reserve
4        account principal maximum amount shall be distributed
5        as follows: (i) if retail customers have not realized
6        net consumer savings, calculated by comparing the
7        delivered SNG price to the weighted average of the
8        daily Chicago City-gate price on a daily basis over the
9        entire term of the sourcing agreement to date, then 50%
10        of any amounts in the consumer protection reserve
11        account in excess of the consumer protection reserve
12        account principal maximum shall be distributed to the
13        clean coal SNG brownfield facility, with the remaining
14        50% of any such additional amounts being credited to
15        retail customers, and (ii) if retail customers have
16        realized net consumer savings, then 100% of any amounts
17        in the consumer protection reserve account in excess of
18        the consumer protection reserve account principal
19        maximum shall be distributed to the clean coal SNG
20        brownfield facility; provided, however, that under no
21        circumstances shall the total cumulative amount
22        distributed to the clean coal SNG brownfield facility
23        under this subparagraph (B) exceed $150,000,000;
24            (C) to the extent there is an overage amount, after
25        distributing the amounts pursuant to subparagraph (B)
26        of this paragraph (3), if any, the consumer protection

 

 

HB2414- 31 -LRB098 07848 JLS 37932 b

1        reserve account shall be used to provide a credit to
2        reduce the SNG price by an amount equal to the overage
3        amount;
4            (D) if retail customers have realized net consumer
5        savings, calculated by comparing the delivered SNG
6        price to the weighted average of the daily Chicago
7        City-gate price on a daily basis over the entire term
8        of the sourcing agreement to date, then after
9        distributing the amounts pursuant to subparagraphs (B)
10        and (C) of this paragraph (3), 50% of any additional
11        amounts in the consumer protection reserve account in
12        excess of the consumer protection reserve account
13        principal maximum shall be distributed to the clean
14        coal SNG brownfield facility, with the remaining 50% of
15        any such additional amounts being credited to retail
16        customers; provided, however, that if retail customers
17        have not realized such net consumer savings, no such
18        distribution shall be made to the clean coal SNG
19        brownfield facility, and 100% of such additional
20        amounts shall be credited to the retail customers to
21        the extent the consumer protection reserve account
22        exceeds the consumer protection reserve account
23        principal maximum amount.
24        (4) Fifty percent of all additional net revenue,
25    defined as miscellaneous net revenue after cost allowance
26    for costs associated with additional net revenue that are

 

 

HB2414- 32 -LRB098 07848 JLS 37932 b

1    not otherwise recoverable pursuant to subsection (h-3) of
2    this Section, including net revenue from sales of
3    substitute natural gas derived from the facility above the
4    nameplate capacity of the facility and other by-products
5    produced by the facility, shall be credited to the consumer
6    protection reserve account.
7        (5) At the conclusion of the term of the sourcing
8    agreement, to the extent retail customers have not saved
9    the minimum of $100,000,000 in consumer savings as
10    guaranteed in this subsection (h-2), amounts in the
11    consumer protection reserve account shall be credited to
12    retail customers to the extent the retail customers have
13    saved the minimum of $100,000,000; 50% of any additional
14    amounts in the consumer protection reserve account shall be
15    distributed to the company, and the remaining 50% shall be
16    distributed to retail customers.
17        (6) If, at the conclusion of the term of the sourcing
18    agreement, the customers have not saved the minimum
19    $100,000,000 in savings as guaranteed in this subsection
20    (h-2) and the consumer protection reserve account has been
21    depleted, then the clean coal SNG brownfield facility shall
22    be liable for any remaining amount owed to the retail
23    customers to the extent that the customers are provided
24    with the $100,000,000 in savings as guaranteed in this
25    subsection (h-2). The retail customers shall have first
26    priority in recovering that debt above any creditors,

 

 

HB2414- 33 -LRB098 07848 JLS 37932 b

1    except the original senior secured lender to the extent
2    that the original senior secured lender has any senior
3    secured debt outstanding, including any clean coal SNG
4    brownfield facility parent companies or affiliates.
5        (7) The clean coal SNG brownfield facility, the
6    utilities, and the trustee shall work together to take
7    commercially reasonable steps to minimize the tax impact of
8    these transactions, while preserving the consumer
9    benefits.
10        (8) The clean coal SNG brownfield facility shall each
11    month, starting in the facility's first year of commercial
12    operation, file with the Commission, in such form as the
13    Commission shall require, a report as to the consumer
14    protection reserve account. The monthly report must
15    contain the following information:
16            (A) the extent the monthly delivered SNG price is
17        greater than, less than, or equal to the Chicago
18        City-gate price;
19            (B) the amount credited or debited to the consumer
20        protection reserve account during the month;
21            (C) the amounts credited to consumers and
22        distributed to the clean coal SNG brownfield facility
23        during the month;
24            (D) the total amount of the consumer protection
25        reserve account at the beginning and end of the month;
26            (E) the total amount of consumer savings to date;

 

 

HB2414- 34 -LRB098 07848 JLS 37932 b

1            (F) a confidential summary of the inputs used to
2        calculate the additional net revenue; and
3            (G) any other additional information the
4        Commission shall require.
5        When any report is erroneous or defective or appears to
6    the Commission to be erroneous or defective, the Commission
7    may notify the clean coal SNG brownfield facility to amend
8    the report within 30 days, and, before or after the
9    termination of the 30-day period, the Commission may
10    examine the trustee of the consumer protection reserve
11    account or the officers, agents, employees, books,
12    records, or accounts of the clean coal SNG brownfield
13    facility and correct such items in the report as upon such
14    examination the Commission may find defective or
15    erroneous. All reports shall be under oath.
16        All reports made to the Commission by the clean coal
17    SNG brownfield facility and the contents of the reports
18    shall be open to public inspection and shall be deemed a
19    public record under the Freedom of Information Act. Such
20    reports shall be preserved in the office of the Commission.
21    The Commission shall publish an annual summary of the
22    reports prior to February 1 of the following year. The
23    annual summary shall be made available to the public on the
24    Commission's website and shall be submitted to the General
25    Assembly.
26        Any facility that fails to file a report required under

 

 

HB2414- 35 -LRB098 07848 JLS 37932 b

1    this paragraph (8) to the Commission within the time
2    specified or to make specific answer to any question
3    propounded by the Commission within 30 days from the time
4    it is lawfully required to do so, or within such further
5    time not to exceed 90 days as may in its discretion be
6    allowed by the Commission, shall pay a penalty of $500 to
7    the Commission for each day it is in default.
8        Any person who willfully makes any false report to the
9    Commission or to any member, officer, or employee thereof,
10    any person who willfully in a report withholds or fails to
11    provide material information to which the Commission is
12    entitled under this paragraph (8) and which information is
13    either required to be filed by statute, rule, regulation,
14    order, or decision of the Commission or has been requested
15    by the Commission, and any person who willfully aids or
16    abets such person shall be guilty of a Class A misdemeanor.
17    (h-3) Recoverable costs and revenue by the clean coal SNG
18brownfield facility.
19        (1) A capital recovery charge approved by the
20    Commission shall be recoverable by the clean coal SNG
21    brownfield facility under a sourcing agreement. The
22    capital recovery charge shall be comprised of capital costs
23    and a reasonable rate of return. "Capital costs" means
24    costs to be incurred in connection with the construction
25    and development of a facility, as defined in Section 1-10
26    of the Illinois Power Agency Act, and such other costs as

 

 

HB2414- 36 -LRB098 07848 JLS 37932 b

1    the Capital Development Board deems appropriate to be
2    recovered in the capital recovery charge.
3            (A) Capital costs. The Capital Development Board
4        shall calculate a range of capital costs that it
5        believes would be reasonable for the clean coal SNG
6        brownfield facility to recover under the sourcing
7        agreement. In making this determination, the Capital
8        Development Board shall review the facility cost
9        report, if any, of the clean coal SNG brownfield
10        facility, adjusting the results based on the change in
11        the Annual Consumer Price Index for All Urban Consumers
12        for the Midwest Region as published in April by the
13        United States Department of Labor, Bureau of Labor
14        Statistics, the final draft of the sourcing agreement,
15        and the rate of return approved by the Commission. In
16        addition, the Capital Development Board may consult as
17        much as it deems necessary with the clean coal SNG
18        brownfield facility and conduct whatever research and
19        investigation it deems necessary.
20            The Capital Development Board shall retain an
21        engineering expert to assist in determining both the
22        range of capital costs and the range of operations and
23        maintenance costs that it believes would be reasonable
24        for the clean coal SNG brownfield facility to recover
25        under the sourcing agreement. Provided, however, that
26        such expert shall: (i) not have been involved in the

 

 

HB2414- 37 -LRB098 07848 JLS 37932 b

1        clean coal SNG brownfield facility's facility cost
2        report, if any, (ii) not own or control any direct or
3        indirect interest in the initial clean coal facility,
4        and (iii) have no contractual relationship with the
5        clean coal SNG brownfield facility. In order to qualify
6        as an independent expert, a person or company must
7        have:
8                (i) direct previous experience conducting
9            front-end engineering and design studies for
10            large-scale energy facilities and administering
11            large-scale energy operations and maintenance
12            contracts, which may be particularized to the
13            specific type of financing associated with the
14            clean coal SNG brownfield facility;
15                (ii) an advanced degree in economics,
16            mathematics, engineering, or a related area of
17            study;
18                (iii) ten years of experience in the energy
19            sector, including construction and risk management
20            experience;
21                (iv) expertise in assisting companies with
22            obtaining financing for large-scale energy
23            projects, which may be particularized to the
24            specific type of financing associated with the
25            clean coal SNG brownfield facility;
26                (v) expertise in operations and maintenance

 

 

HB2414- 38 -LRB098 07848 JLS 37932 b

1            which may be particularized to the specific type of
2            operations and maintenance associated with the
3            clean coal SNG brownfield facility;
4                (vi) expertise in credit and contract
5            protocols;
6                (vii) adequate resources to perform and
7            fulfill the required functions and
8            responsibilities; and
9                (viii) the absence of a conflict of interest
10            and inappropriate bias for or against an affected
11            gas utility or the clean coal SNG brownfield
12            facility.
13            The clean coal SNG brownfield facility and the
14        Illinois Power Agency shall cooperate with the Capital
15        Development Board in any investigation it deems
16        necessary. The Capital Development Board shall make
17        its final determination of the range of capital costs
18        confidentially and shall submit that range to the
19        Commission in a confidential filing within 120 days
20        after July 13, 2011 (the effective date of Public Act
21        97-096). The clean coal SNG brownfield facility shall
22        submit to the Commission its estimate of the capital
23        costs to be recovered under the sourcing agreement.
24        Only after the clean coal SNG brownfield facility has
25        submitted this estimate shall the Commission publicly
26        announce the range of capital costs submitted by the

 

 

HB2414- 39 -LRB098 07848 JLS 37932 b

1        Capital Development Board.
2            In the event that the estimate submitted by the
3        clean coal SNG brownfield facility is within or below
4        the range submitted by the Capital Development Board,
5        the clean coal SNG brownfield facility's estimate
6        shall be approved by the Commission as the amount of
7        capital costs to be recovered under the sourcing
8        agreement. In the event that the estimate submitted by
9        the clean coal SNG brownfield facility is above the
10        range submitted by the Capital Development Board, the
11        amount of capital costs at the lowest end of the range
12        submitted by the Capital Development Board shall be
13        approved by the Commission as the amount of capital
14        costs to be recovered under the sourcing agreement.
15        Within 15 days after the Capital Development Board has
16        submitted its range and the clean coal SNG brownfield
17        facility has submitted its estimate, the Commission
18        shall approve the capital costs for the clean coal SNG
19        brownfield facility.
20            The Capital Development Board shall monitor the
21        construction of the clean coal SNG brownfield facility
22        for the full duration of construction to assess
23        potential cost overruns. The Capital Development
24        Board, in its discretion, may retain an expert to
25        facilitate such monitoring. The clean coal SNG
26        brownfield facility shall pay a reasonable fee as

 

 

HB2414- 40 -LRB098 07848 JLS 37932 b

1        required by the Capital Development Board for the
2        Capital Development Board's services under this
3        subsection (h-3) to be deposited into the Capital
4        Development Board Revolving Fund, and such fee shall
5        not be passed through to a utility or its customers. If
6        an expert is retained by the Capital Development Board
7        for monitoring of construction, then the clean coal SNG
8        brownfield facility must pay for the expert's
9        reasonable fees and such costs shall not be passed
10        through to a utility or its customers.
11            (B) Rate of Return. No later than 30 days after the
12        date on which the Illinois Power Agency submits a final
13        draft sourcing agreement, the Commission shall hold a
14        public hearing to determine the rate of return to be
15        recovered under the sourcing agreement. Rate of return
16        shall be comprised of the clean coal SNG brownfield
17        facility's actual cost of debt, including
18        mortgage-style amortization, and a reasonable return
19        on equity. The Commission shall post notice of the
20        hearing on its website no later than 10 days prior to
21        the date of the hearing. The Commission shall provide
22        the public and all interested parties, including the
23        gas utilities, the Attorney General, and the Illinois
24        Power Agency, an opportunity to be heard.
25            In determining the return on equity, the
26        Commission shall select a commercially reasonable

 

 

HB2414- 41 -LRB098 07848 JLS 37932 b

1        return on equity taking into account the return on
2        equity being received by developers of similar
3        facilities in or outside of Illinois, the need to
4        balance an incentive for clean-coal technology with
5        the need to protect ratepayers from high gas prices,
6        the risks being borne by the clean coal SNG brownfield
7        facility in the final draft sourcing agreement, and any
8        other information that the Commission may deem
9        relevant. The Commission may establish a return on
10        equity that varies with the amount of savings, if any,
11        to customers during the term of the sourcing agreement,
12        comparing the delivered SNG price to a daily weighted
13        average price of natural gas, based upon an index. The
14        Illinois Power Agency shall recommend a return on
15        equity to the Commission using the same criteria.
16        Within 60 days after receiving the final draft sourcing
17        agreement from the Illinois Power Agency, the
18        Commission shall approve the rate of return for the
19        clean coal brownfield facility. Within 30 days after
20        obtaining debt financing for the clean coal SNG
21        brownfield facility, the clean coal SNG brownfield
22        facility shall file a notice with the Commission
23        identifying the actual cost of debt.
24        (2) Operations and maintenance costs approved by the
25    Commission shall be recoverable by the clean coal SNG
26    brownfield facility under the sourcing agreement. The

 

 

HB2414- 42 -LRB098 07848 JLS 37932 b

1    operations and maintenance costs mean costs that have been
2    incurred for the administration, supervision, operation,
3    maintenance, preservation, and protection of the clean
4    coal SNG brownfield facility's physical plant.
5        The Capital Development Board shall calculate a range
6    of operations and maintenance costs that it believes would
7    be reasonable for the clean coal SNG brownfield facility to
8    recover under the sourcing agreement, incorporating an
9    inflation index or combination of inflation indices to most
10    accurately reflect the actual costs of operating the clean
11    coal SNG brownfield facility. In making this
12    determination, the Capital Development Board shall review
13    the facility cost report, if any, of the clean coal SNG
14    brownfield facility, adjusting the results for inflation
15    based on the change in the Annual Consumer Price Index for
16    All Urban Consumers for the Midwest Region as published in
17    April by the United States Department of Labor, Bureau of
18    Labor Statistics, the final draft of the sourcing
19    agreement, and the rate of return approved by the
20    Commission. In addition, the Capital Development Board may
21    consult as much as it deems necessary with the clean coal
22    SNG brownfield facility and conduct whatever research and
23    investigation it deems necessary. As set forth in
24    subparagraph (A) of paragraph (1) of this subsection (h-3),
25    the Capital Development Board shall retain an independent
26    engineering expert to assist in determining both the range

 

 

HB2414- 43 -LRB098 07848 JLS 37932 b

1    of operations and maintenance costs that it believes would
2    be reasonable for the clean coal SNG brownfield facility to
3    recover under the sourcing agreement. The clean coal SNG
4    brownfield facility and the Illinois Power Agency shall
5    cooperate with the Capital Development Board in any
6    investigation it deems necessary. The Capital Development
7    Board shall make its final determination of the range of
8    operations and maintenance costs confidentially and shall
9    submit that range to the Commission in a confidential
10    filing within 120 days after July 13, 2011.
11        The clean coal SNG brownfield facility shall submit to
12    the Commission its estimate of the operations and
13    maintenance costs to be recovered under the sourcing
14    agreement. Only after the clean coal SNG brownfield
15    facility has submitted this estimate shall the Commission
16    publicly announce the range of operations and maintenance
17    costs submitted by the Capital Development Board. In the
18    event that the estimate submitted by the clean coal SNG
19    brownfield facility is within or below the range submitted
20    by the Capital Development Board, the clean coal SNG
21    brownfield facility's estimate shall be approved by the
22    Commission as the amount of operations and maintenance
23    costs to be recovered under the sourcing agreement. In the
24    event that the estimate submitted by the clean coal SNG
25    brownfield facility is above the range submitted by the
26    Capital Development Board, the amount of operations and

 

 

HB2414- 44 -LRB098 07848 JLS 37932 b

1    maintenance costs at the lowest end of the range submitted
2    by the Capital Development Board shall be approved by the
3    Commission as the amount of operations and maintenance
4    costs to be recovered under the sourcing agreement. Within
5    15 days after the Capital Development Board has submitted
6    its range and the clean coal SNG brownfield facility has
7    submitted its estimate, the Commission shall approve the
8    operations and maintenance costs for the clean coal SNG
9    brownfield facility.
10        The clean coal SNG brownfield facility shall pay for
11    the independent engineering expert's reasonable fees and
12    such costs shall not be passed through to a utility or its
13    customers. The clean coal SNG brownfield facility shall pay
14    a reasonable fee as required by the Capital Development
15    Board for the Capital Development Board's services under
16    this subsection (h-3) to be deposited into the Capital
17    Development Board Revolving Fund, and such fee shall not be
18    passed through to a utility or its customers.
19        (3) Sequestration costs approved by the Commission
20    shall be recoverable by the clean coal SNG brownfield
21    facility. "Sequestration costs" means costs to be incurred
22    by the clean coal SNG brownfield facility in accordance
23    with its Commission-approved carbon capture and
24    sequestration plan to:
25            (A) capture carbon dioxide;
26            (B) build, operate, and maintain a sequestration

 

 

HB2414- 45 -LRB098 07848 JLS 37932 b

1        site in which carbon dioxide may be injected;
2            (C) build, operate, and maintain a carbon dioxide
3        pipeline; and
4            (D) transport the carbon dioxide to the
5        sequestration site or a pipeline.
6        The Commission shall assess the prudency of the
7    sequestration costs for the clean coal SNG brownfield
8    facility before construction commences at the
9    sequestration site or pipeline. Any revenues the clean coal
10    SNG brownfield facility receives as a result of the
11    capture, transportation, or sequestration of carbon
12    dioxide shall be first credited against all sequestration
13    costs, with the positive balance, if any, treated as
14    additional net revenue.
15        The Commission may, in its discretion, retain an expert
16    to assist in its review of sequestration costs. The clean
17    coal SNG brownfield facility shall pay for the expert's
18    reasonable fees if an expert is retained by the Commission,
19    and such costs shall not be passed through to a utility or
20    its customers. Once made, the Commission's determination
21    of the amount of recoverable sequestration costs shall not
22    be increased unless the clean coal SNG brownfield facility
23    can show by clear and convincing evidence that (i) the
24    costs were not reasonably foreseeable; (ii) the costs were
25    due to circumstances beyond the clean coal SNG brownfield
26    facility's control; and (iii) the clean coal SNG brownfield

 

 

HB2414- 46 -LRB098 07848 JLS 37932 b

1    facility took all reasonable steps to mitigate the costs.
2    If the Commission determines that sequestration costs may
3    be increased, the Commission shall provide for notice and a
4    public hearing for approval of the increased sequestration
5    costs.
6        (4) Actual delivered and processed fuel costs shall be
7    set by the Illinois Power Agency through a SNG feedstock
8    procurement, pursuant to Sections 1-20, 1-77, and 1-78 of
9    the Illinois Power Agency Act, to be performed at least
10    every 5 years and purchased by the clean coal SNG
11    brownfield facility pursuant to feedstock procurement
12    contracts developed by the Illinois Power Agency, with coal
13    comprising at least 50% of the total feedstock over the
14    term of the sourcing agreement and petroleum coke
15    comprising the remainder of the SNG feedstock. If the
16    Commission fails to approve a feedstock procurement plan or
17    fails to approve the results of a feedstock procurement
18    event, then the fuel shall be purchased by the company
19    month-by-month on the spot market and those actual
20    delivered and processed fuel costs shall be recoverable
21    under the sourcing agreement. If a supplier defaults under
22    the terms of a procurement contract, then the Illinois
23    Power Agency shall immediately initiate a feedstock
24    procurement process to obtain a replacement supply, and,
25    prior to the conclusion of that process, fuel shall be
26    purchased by the company month-by-month on the spot market

 

 

HB2414- 47 -LRB098 07848 JLS 37932 b

1    and those actual delivered and processed fuel costs shall
2    be recoverable under the sourcing agreement.
3        (5) Taxes and fees imposed by the federal government,
4    the State, or any unit of local government applicable to
5    the clean coal SNG brownfield facility, excluding income
6    tax, shall be recoverable by the clean coal SNG brownfield
7    facility under the sourcing agreement to the extent such
8    taxes and fees were not applicable to the facility on July
9    13, 2011.
10        (6) The actual transportation costs, in accordance
11    with the applicable utility's tariffs, and third-party
12    marketer costs incurred by the company, if any, associated
13    with transporting the SNG from the clean coal SNG
14    brownfield facility to the Chicago City-gate to sell such
15    SNG into the natural gas markets shall be recoverable under
16    the sourcing agreement.
17        (7) Unless otherwise provided, within 30 days after a
18    decision of the Commission on recoverable costs under this
19    Section, any interested party to the Commission's decision
20    may apply for a rehearing with respect to the decision. The
21    Commission shall receive and consider the application for
22    rehearing and shall grant or deny the application in whole
23    or in part within 20 days after the date of the receipt of
24    the application by the Commission. If no rehearing is
25    applied for within the required 30 days or an application
26    for rehearing is denied, then the Commission decision shall

 

 

HB2414- 48 -LRB098 07848 JLS 37932 b

1    be final. If an application for rehearing is granted, then
2    the Commission shall hold a rehearing within 30 days after
3    granting the application. The decision of the Commission
4    upon rehearing shall be final.
5        Any person affected by a decision of the Commission
6    under this subsection (h-3) may have the decision reviewed
7    only under and in accordance with the Administrative Review
8    Law. Unless otherwise provided, the provisions of the
9    Administrative Review Law, all amendments and
10    modifications to that Law, and the rules adopted pursuant
11    to that Law shall apply to and govern all proceedings for
12    the judicial review of final administrative decisions of
13    the Commission under this subsection (h-3). The term
14    "administrative decision" is defined as in Section 3-101 of
15    the Code of Civil Procedure.
16        (8) The Capital Development Board shall adopt and make
17    public a policy detailing the process for retaining experts
18    under this Section. Any experts retained to assist with
19    calculating the range of capital costs or operations and
20    maintenance costs shall be retained no later than 45 days
21    after July 13, 2011.
22    (h-4) No later than 90 days after the Illinois Power Agency
23submits the final draft sourcing agreement pursuant to
24subsection (h-1), the Commission shall approve a sourcing
25agreement containing (i) the capital costs, rate of return, and
26operations and maintenance costs established pursuant to

 

 

HB2414- 49 -LRB098 07848 JLS 37932 b

1subsection (h-3) and (ii) all other terms and conditions,
2rights, provisions, exceptions, and limitations contained in
3the final draft sourcing agreement; provided, however, the
4Commission shall correct typographical and scrivener's errors
5and modify the contract only as necessary to provide that the
6gas utility does not have the right to terminate the sourcing
7agreement due to any future events that may occur other than
8the clean coal SNG brownfield facility's failure to timely meet
9milestones, uncured default, extended force majeure, or
10abandonment. Once the sourcing agreement is approved, then the
11gas utility subject to that sourcing agreement shall have 45
12days after the date of the Commission's approval to enter into
13the sourcing agreement.
14    (h-5) Sequestration enforcement.
15        (A) All contracts entered into under subsection (h) of
16    this Section and all sourcing agreements under subsection
17    (h-1) of this Section, regardless of duration, shall
18    require the owner of any facility supplying SNG under the
19    contract or sourcing agreement to provide certified
20    documentation to the Commission each year, starting in the
21    facility's first year of commercial operation, accurately
22    reporting the quantity of carbon dioxide emissions from the
23    facility that have been captured and sequestered and
24    reporting any quantities of carbon dioxide released from
25    the site or sites at which carbon dioxide emissions were
26    sequestered in prior years, based on continuous monitoring

 

 

HB2414- 50 -LRB098 07848 JLS 37932 b

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

 

 

HB2414- 51 -LRB098 07848 JLS 37932 b

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

 

 

HB2414- 52 -LRB098 07848 JLS 37932 b

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

 

 

HB2414- 53 -LRB098 07848 JLS 37932 b

1    clean coal SNG facility or a clean coal SNG brownfield
2    facility if the facility fails to fully comply with the
3    applicable carbon sequestration sequestrian requirements
4    in any given year, provided the requisite offsets are
5    purchased or requisite penalties are paid.
6        In addition, carbon dioxide emission credits received
7    by the clean coal SNG facility in connection with
8    sequestration of carbon dioxide from the facility must be
9    sold in a timely fashion with any revenue, less applicable
10    fees and expenses and any expenses required to be paid by
11    facility for carbon dioxide transportation or
12    sequestration, deposited into the reconciliation account
13    within 30 days after receipt of such funds by the owner of
14    the clean coal SNG facility.
15        The clean coal SNG facility is prohibited from
16    transporting or sequestering carbon dioxide unless the
17    owner of the carbon dioxide pipeline that transfers the
18    carbon dioxide from the facility and the owner of the
19    sequestration site where the carbon dioxide captured by the
20    facility is stored has acquired all applicable permits
21    under applicable State and federal laws, statutes, rules,
22    or regulations prior to the transfer or sequestration of
23    carbon dioxide. The responsibility for compliance with the
24    sequestration requirements specified in this subsection
25    (h-5) for the clean coal SNG facility shall reside solely
26    with the clean coal SNG facility, regardless of whether the

 

 

HB2414- 54 -LRB098 07848 JLS 37932 b

1    facility has contracted with another party to capture,
2    transport, or sequester carbon dioxide.
3        (C) If, in any year, the owner of a clean coal SNG
4    brownfield facility fails to demonstrate that the clean
5    coal SNG brownfield facility captured and sequestered at
6    least 85% of the total carbon dioxide emissions that the
7    facility would otherwise emit, then the owner of the clean
8    coal SNG brownfield facility must pay a penalty of $20 per
9    ton of excess carbon emissions up to $20,000,000, which
10    shall be deposited into the Energy Efficiency Trust Fund
11    and distributed pursuant to subsection (b) of Section 6-6
12    of the Renewable Energy, Energy Efficiency, and Coal
13    Resources Development Law of 1997. Provided, however, to
14    the extent that the owner of the clean coal SNG brownfield
15    facility can demonstrate that the failure was as a result
16    of acts of God (including fire, flood, earthquake, tornado,
17    lightning, hurricane, or other natural disaster); any
18    amendment, modification, or abrogation of any applicable
19    law or regulation that would prevent performance; war;
20    invasion; act of foreign enemies; hostilities (regardless
21    of whether war is declared); civil war; rebellion;
22    revolution; insurrection; military or usurped power or
23    confiscation; terrorist activities; civil disturbances;
24    riots; nationalization; sabotage; blockage; or embargo,
25    the owner of the clean coal SNG brownfield facility shall
26    not be subject to a penalty if and only if (i) it promptly

 

 

HB2414- 55 -LRB098 07848 JLS 37932 b

1    provides notice of its failure to the Commission; (ii) as
2    soon as practicable and consistent with any order or
3    direction from the Commission, it submits to the Commission
4    proposed modifications to its carbon capture and
5    sequestration plan; and (iii) it carries out its proposed
6    modifications in the manner and time directed by the
7    Commission. If the Commission finds that the facility has
8    not satisfied each of these requirements, then the facility
9    shall be subject to the penalty. If the owner of a clean
10    coal SNG brownfield facility demonstrates that the clean
11    coal SNG brownfield facility captured and sequestered more
12    than 85% of the total carbon emissions that the facility
13    would otherwise emit, the owner of the clean coal SNG
14    brownfield facility may credit such additional amounts to
15    reduce the amount of any future penalty to be paid. The
16    penalty resulting from the failure to capture and sequester
17    at least the minimum amount of carbon dioxide shall not be
18    passed on to a utility or its customers.
19        In addition to any penalty for the clean coal SNG
20    brownfield facility's failure to capture and sequester at
21    least its minimum sequestration requirement, the Attorney
22    General, on behalf of the People of the State of Illinois,
23    shall bring an action for specific performance of this
24    subsection (h-5). Such action may be filed in any circuit
25    court in Illinois. By entering into a sourcing agreement
26    pursuant to subsection (h-1) of this Section, the clean

 

 

HB2414- 56 -LRB098 07848 JLS 37932 b

1    coal SNG brownfield facility agrees to waive any objections
2    to venue or to the jurisdiction of the court with regard to
3    the Attorney General's action for specific performance
4    under this subsection (h-5).
5        Compliance with the sequestration requirements and
6    penalty requirements specified in this subsection (h-5)
7    for the clean coal SNG brownfield facility shall be
8    assessed annually by the Commission, which may in its
9    discretion retain an expert to facilitate its assessment.
10    If an expert is retained by the Commission, then the clean
11    coal SNG brownfield facility shall pay for the expert's
12    reasonable fees, and such costs shall not be passed through
13    to a utility or its customers.
14        Responsibility for compliance with the sequestration
15    requirements specified in this subsection (h-5) for the
16    clean coal SNG brownfield facility shall reside solely with
17    the clean coal SNG brownfield facility regardless of
18    whether the facility has contracted with another party to
19    capture, transport, or sequester carbon dioxide.
20    (h-7) Sequestration permitting, oversight, and
21investigations.
22        (1) No clean coal facility or clean coal SNG brownfield
23    facility may transport or sequester carbon dioxide unless
24    the Commission approves the method of carbon dioxide
25    transportation or sequestration. Such approval shall be
26    required regardless of whether the facility has contracted

 

 

HB2414- 57 -LRB098 07848 JLS 37932 b

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

 

 

HB2414- 58 -LRB098 07848 JLS 37932 b

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

 

 

HB2414- 59 -LRB098 07848 JLS 37932 b

1    approve or deny the carbon dioxide transportation or
2    sequestration method within 90 days after the receipt of
3    all required information.
4        (3) At least annually, the Illinois Environmental
5    Protection Agency shall inspect all carbon dioxide
6    sequestration sites in Illinois. The Illinois
7    Environmental Protection Agency may, as often as deemed
8    necessary, monitor and conduct investigations of those
9    sites. The owner or operator of the sequestration site must
10    cooperate with the Illinois Environmental Protection
11    Agency investigations of carbon dioxide sequestration
12    sites.
13        If the Illinois Environmental Protection Agency
14    determines at any time a site creates conditions that
15    warrant the issuance of a seal order under Section 34 of
16    the Environmental Protection Act, then the Illinois
17    Environmental Protection Agency shall seal the site
18    pursuant to the Environmental Protection Act. If the
19    Illinois Environmental Protection Agency determines at any
20    time a carbon dioxide sequestration site creates
21    conditions that warrant the institution of a civil action
22    for an injunction under Section 43 of the Environmental
23    Protection Act, then the Illinois Environmental Protection
24    Agency shall request the State's Attorney or the Attorney
25    General institute such action. The Illinois Environmental
26    Protection Agency shall provide notice of any such actions

 

 

HB2414- 60 -LRB098 07848 JLS 37932 b

1    as soon as possible on its website. The SNG facility shall
2    incur all reasonable costs associated with any such
3    inspection or monitoring of the sequestration sites, and
4    these costs shall not be recoverable from utilities or
5    their customers.
6        (4) (Blank).
7    (h-9) The clean coal SNG brownfield facility shall have the
8right to recover prudently incurred increased costs or reduced
9revenue resulting from any new or amendatory legislation or
10other action. The State of Illinois pledges that the State will
11not enact any law or take any action to:
12        (1) break, or repeal the authority for, sourcing
13    agreements approved by the Commission and entered into
14    between public utilities and the clean coal SNG brownfield
15    facility;
16        (2) deny public utilities full cost recovery for their
17    costs incurred under those sourcing agreements; or
18        (3) deny the clean coal SNG brownfield facility full
19    cost and revenue recovery as provided under those sourcing
20    agreements that are recoverable pursuant to subsection
21    (h-3) of this Section.
22    These pledges are for the benefit of the parties to those
23sourcing agreements and the issuers and holders of bonds or
24other obligations issued or incurred to finance or refinance
25the clean coal SNG brownfield facility. The clean coal SNG
26brownfield facility is authorized to include and refer to these

 

 

HB2414- 61 -LRB098 07848 JLS 37932 b

1pledges in any financing agreement into which it may enter in
2regard to those sourcing agreements.
3    The State of Illinois retains and reserves all other rights
4to enact new or amendatory legislation or take any other
5action, without impairment of the right of the clean coal SNG
6brownfield facility to recover prudently incurred increased
7costs or reduced revenue resulting from the new or amendatory
8legislation or other action, including, but not limited to,
9such legislation or other action that would (i) directly or
10indirectly raise the costs the clean coal SNG brownfield
11facility must incur; (ii) directly or indirectly place
12additional restrictions, regulations, or requirements on the
13clean coal SNG brownfield facility; (iii) prohibit
14sequestration in general or prohibit a specific sequestration
15method or project; or (iv) increase minimum sequestration
16requirements for the clean coal SNG brownfield facility to the
17extent technically feasible. The clean coal SNG brownfield
18facility shall have the right to recover prudently incurred
19increased costs or reduced revenue resulting from the new or
20amendatory legislation or other action as described in this
21subsection (h-9).
22    (h-10) Contract costs for SNG incurred by an Illinois gas
23utility are reasonable and prudent and recoverable through the
24purchased gas adjustment clause and are not subject to review
25or disallowance by the Commission. Contract costs are costs
26incurred by the utility under the terms of a contract that

 

 

HB2414- 62 -LRB098 07848 JLS 37932 b

1incorporates the terms stated in subsection (h) of this Section
2as confirmed in writing by the Illinois Power Agency as set
3forth in subsection (h) of this Section, which confirmation
4shall be deemed conclusive, or as a consequence of or condition
5to its performance under the contract, including (i) amounts
6paid for SNG under the SNG contract and (ii) costs of
7transportation and storage services of SNG purchased from
8interstate pipelines under federally approved tariffs. The
9Illinois gas utility shall initiate a clean coal SNG facility
10rider mechanism that (A) shall be applicable to all customers
11who receive transportation service from the utility, (B) shall
12be designed to have an equal percentage impact on the
13transportation services rates of each class of the utility's
14total customers, and (C) shall accurately reflect the net
15customer savings, if any, and above market costs, if any, under
16the SNG contract. Any contract, the terms of which have been
17confirmed in writing by the Illinois Power Agency as set forth
18in subsection (h) of this Section and the performance of the
19parties under such contract cannot be grounds for challenging
20prudence or cost recovery by the utility through the purchased
21gas adjustment clause, and in such cases, the Commission is
22directed not to consider, and has no authority to consider, any
23attempted challenges.
24    The contracts entered into by Illinois gas utilities
25pursuant to subsection (h) of this Section shall provide that
26the utility retains the right to terminate the contract without

 

 

HB2414- 63 -LRB098 07848 JLS 37932 b

1further obligation or liability to any party if the contract
2has been impaired as a result of any legislative,
3administrative, judicial, or other governmental action that is
4taken that eliminates all or part of the prudence protection of
5this subsection (h-10) or denies the recoverability of all or
6part of the contract costs through the purchased gas adjustment
7clause. Should any Illinois gas utility exercise its right
8under this subsection (h-10) to terminate the contract, all
9contract costs incurred prior to termination are and will be
10deemed reasonable, prudent, and recoverable as and when
11incurred and not subject to review or disallowance by the
12Commission. Any order, issued by the State requiring or
13authorizing the discontinuation of the merchant function,
14defined as the purchase and sale of natural gas by an Illinois
15gas utility for the ultimate consumer in its service territory
16shall include provisions necessary to prevent the impairment of
17the value of any contract hereunder over its full term.
18    (h-11) All costs incurred by an Illinois gas utility in
19procuring SNG from a clean coal SNG brownfield facility
20pursuant to subsection (h-1) or a third-party marketer pursuant
21to subsection (h-1) are reasonable and prudent and recoverable
22through the purchased gas adjustment clause in conjunction with
23a SNG brownfield facility rider mechanism and are not subject
24to review or disallowance by the Commission; provided that if a
25utility is required by law or otherwise elects to connect the
26clean coal SNG brownfield facility to an interstate pipeline,

 

 

HB2414- 64 -LRB098 07848 JLS 37932 b

1then the utility shall be entitled to recover pursuant to its
2tariffs all just and reasonable costs that are prudently
3incurred. Sourcing agreement costs are costs incurred by the
4utility under the terms of a sourcing agreement that
5incorporates the terms stated in subsection (h-1) of this
6Section as approved by the Commission as set forth in
7subsection (h-4) of this Section, which approval shall be
8deemed conclusive, or as a consequence of or condition to its
9performance under the contract, including (i) amounts paid for
10SNG under the SNG contract and (ii) costs of transportation and
11storage services of SNG purchased from interstate pipelines
12under federally approved tariffs. Any sourcing agreement, the
13terms of which have been approved by the Commission as set
14forth in subsection (h-4) of this Section, and the performance
15of the parties under the sourcing agreement cannot be grounds
16for challenging prudence or cost recovery by the utility, and
17in these cases, the Commission is directed not to consider, and
18has no authority to consider, any attempted challenges.
19    (h-15) Reconciliation account. The clean coal SNG facility
20shall establish a reconciliation account for the benefit of the
21retail customers of the utilities that have entered into
22contracts with the clean coal SNG facility pursuant to
23subsection (h). The reconciliation account shall be maintained
24and administered by an independent trustee that is mutually
25agreed upon by the owners of the clean coal SNG facility, the
26utilities, and the Commission in an interest-bearing account in

 

 

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1accordance with the following:
2        (1) The clean coal SNG facility shall conduct an
3    analysis annually within 60 days after receiving the
4    necessary cost information, which shall be provided by the
5    gas utility within 6 months after the end of the preceding
6    calendar year, to determine (i) the average annual contract
7    SNG cost, which shall be calculated as the total amount
8    paid for SNG purchased from the clean coal SNG facility
9    over the preceding 12 months, plus the cost to the utility
10    of the required transportation and storage services of SNG,
11    divided by the total number of MMBtus of SNG actually
12    purchased from the clean coal SNG facility in the preceding
13    12 months under the utility contract; (ii) the average
14    annual natural gas purchase cost, which shall be calculated
15    as the total annual supply costs paid for baseload natural
16    gas (excluding any SNG) purchased by such utility over the
17    preceding 12 months plus the costs of transportation and
18    storage services of such natural gas (excluding such costs
19    for SNG), divided by the total number of MMbtus of baseload
20    natural gas (excluding SNG) actually purchased by the
21    utility during the year; (iii) the cost differential, which
22    shall be the difference between the average annual contract
23    SNG cost and the average annual natural gas purchase cost;
24    and (iv) the revenue share target which shall be the cost
25    differential multiplied by the total amount of SNG
26    purchased over the preceding 12 months under such utility

 

 

HB2414- 66 -LRB098 07848 JLS 37932 b

1    contract.
2            (A) To the extent the annual average contract SNG
3        cost is less than the annual average natural gas
4        purchase cost, the utility shall credit an amount equal
5        to the revenue share target to the reconciliation
6        account. Such credit payment shall be made monthly
7        starting within 30 days after the completed analysis in
8        this subsection (h-15) and based on collections from
9        all customers via a line item charge in all customer
10        bills designed to have an equal percentage impact on
11        the transportation services of each class of
12        customers. Credit payments made pursuant to this
13        subparagraph (A) shall be deemed prudent and
14        reasonable and not subject to Commission prudence
15        review.
16            (B) To the extent the annual average contract SNG
17        cost is greater than the annual average natural gas
18        purchase cost, the reconciliation account shall be
19        used to provide a credit equal to the revenue share
20        target to the utilities to be used to reduce the
21        utility's natural gas costs through the purchased gas
22        adjustment clause. Such payment shall be made within 30
23        days after the completed analysis pursuant to this
24        subsection (h-15), but only to the extent that the
25        reconciliation account has a positive balance.
26        (2) At the conclusion of the term of the SNG contracts

 

 

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

 

 

HB2414- 68 -LRB098 07848 JLS 37932 b

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

 

 

HB2414- 69 -LRB098 07848 JLS 37932 b

1    made within 30 days after the end of each calendar year
2    during the term of the contract.
3        (4) The clean coal SNG facility shall each year,
4    starting in the facility's first year of commercial
5    operation, file with the Commission, in such form as the
6    Commission shall require, a report as to the reconciliation
7    account. The annual report must contain the following
8    information:
9            (A) the revenue share target amount;
10            (B) the amount credited or debited to the
11        reconciliation account during the year;
12            (C) the amount credited to the utilities to be used
13        to reduce the utilities natural gas costs though the
14        purchase gas adjustment clause;
15            (D) the total amount of reconciliation account at
16        the beginning and end of the year;
17            (E) the total amount of consumer savings to date;
18        and
19            (F) any additional information the Commission may
20        require.
21    When any report is erroneous or defective or appears to the
22Commission to be erroneous or defective, the Commission may
23notify the clean coal SNG facility to amend the report within
2430 days; before or after the termination of the 30-day period,
25the Commission may examine the trustee of the reconciliation
26account or the officers, agents, employees, books, records, or

 

 

HB2414- 70 -LRB098 07848 JLS 37932 b

1accounts of the clean coal SNG facility and correct such items
2in the report as upon such examination the Commission may find
3defective or erroneous. All reports shall be under oath.
4    All reports made to the Commission by the clean coal SNG
5facility and the contents of the reports shall be open to
6public inspection and shall be deemed a public record under the
7Freedom of Information Act. Such reports shall be preserved in
8the office of the Commission. The Commission shall publish an
9annual summary of the reports prior to February 1 of the
10following year. The annual summary shall be made available to
11the public on the Commission's website and shall be submitted
12to the General Assembly.
13    Any facility that fails to file the report required under
14this paragraph (4) to the Commission within the time specified
15or to make specific answer to any question propounded by the
16Commission within 30 days after the time it is lawfully
17required to do so, or within such further time not to exceed 90
18days as may be allowed by the Commission in its discretion,
19shall pay a penalty of $500 to the Commission for each day it
20is in default.
21    Any person who willfully makes any false report to the
22Commission or to any member, officer, or employee thereof, any
23person who willfully in a report withholds or fails to provide
24material information to which the Commission is entitled under
25this paragraph (4) and which information is either required to
26be filed by statute, rule, regulation, order, or decision of

 

 

HB2414- 71 -LRB098 07848 JLS 37932 b

1the Commission or has been requested by the Commission, and any
2person who willfully aids or abets such person shall be guilty
3of a Class A misdemeanor.
4    (h-20) The General Assembly authorizes the Illinois
5Finance Authority to issue bonds to the maximum extent
6permitted to finance coal gasification facilities described in
7this Section, which constitute both "industrial projects"
8under Article 801 of the Illinois Finance Authority Act and
9"clean coal and energy projects" under Sections 825-65 through
10825-75 of the Illinois Finance Authority Act.
11    Administrative costs incurred by the Illinois Finance
12Authority in performance of this subsection (h-20) shall be
13subject to reimbursement by the clean coal SNG facility on
14terms as the Illinois Finance Authority and the clean coal SNG
15facility may agree. The utility and its customers shall have no
16obligation to reimburse the clean coal SNG facility or the
17Illinois Finance Authority 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

 

 

HB2414- 72 -LRB098 07848 JLS 37932 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. 96-1364, eff. 7-28-10; 97-96, eff. 7-13-11;
2097-239, eff. 8-2-11; 97-630, eff. 12-8-11; 97-906, eff. 8-7-12;
2197-1081, eff. 8-24-12; revised 1-24-13.)
 
22    (220 ILCS 5/9-244.5 new)
23    Sec. 9-244.5. Natural gas infrastructure investment and
24modernization; regulatory reform.
25    (a) The General Assembly recognizes that for well over a

 

 

HB2414- 73 -LRB098 07848 JLS 37932 b

1century Illinois residents and businesses have been
2well-served by and have benefitted from a comprehensive natural
3gas utility system. The General Assembly finds that natural gas
4utilities are now entering a new construction cycle that is
5needed to refurbish, rebuild, modernize, and expand systems to
6continue to provide safe, reliable, and affordable service to
7the State's current and future utility customers. In
8particular, the General Assembly finds that it is the policy of
9this State that significant investments must be made in the
10State's natural gas transmission and distribution system over
11the next 10 years to modernize and upgrade transmission and
12distribution facilities in the State. These investments will
13ensure that the State's natural gas utility infrastructure will
14promote future economic development and job creation in the
15State and that the State's natural gas utilities will be able
16to continue to provide quality natural gas service to their
17customers. These investments may include innovative
18technological offerings that will create and promote savings
19opportunities for customers by providing them with additional
20use of modern natural gas-fired appliances that will enhance
21customer experience and timely data that allows them to make
22more informed decisions concerning their gas usage and may
23enhance customers' ability to use energy efficient equipment
24dependent on a modernized system. Additionally these
25investments will also ensure that the State's gas transmission,
26distribution, and underground gas storage systems and related

 

 

HB2414- 74 -LRB098 07848 JLS 37932 b

1natural gas utility infrastructure are modernized and upgraded
2and continue to be safe and reliable. The introduction of
3performance metrics will further ensure that reliability and
4other indicators are not just maintained but improved over the
5next decade.
6    The General Assembly further finds that regulatory reform
7measures that increase predictability, stability, and
8transparency in the ratemaking process are needed to promote
9prudent, long-term infrastructure investment and to mutually
10benefit the State's natural gas utilities and their customers,
11regulators, and investors.
12    (b) For purposes of this Section, "participating utility"
13means a natural gas utility serving fewer than 1,100,000
14customers as of January 1, 2013, or a combination utility that
15voluntarily elects and commits to undertake (i) the
16infrastructure investment program consisting of the
17commitments and obligations described in this subsection (b),
18and (ii) the customer assistance program consisting of the
19commitments and obligations described in subsection (b-10) of
20this Section, notwithstanding any other provisions of this Act
21and without obtaining any approvals from the Commission or any
22other agency other than as set forth in this Section,
23regardless of whether any such approval would otherwise be
24required. "Combination utility" means a utility that, as of
25January 1, 2012, provided electric service to at least
261,000,000 retail customers in Illinois and gas service to at

 

 

HB2414- 75 -LRB098 07848 JLS 37932 b

1least 500,000 retail customers in Illinois. A participating
2utility shall recover the expenditures made under the
3infrastructure investment program through the ratemaking
4process, including, but not limited to, the performance-based
5formula rate and process set forth in this Section. Illinois
6natural gas utilities that are affiliated by virtue of a common
7parent company, at the utilities' request, shall be considered
8a single gas utility for the sole purposes of determining: (1)
9if the utilities created the required number of full-time
10equivalent jobs and made the required level of investment under
11this subsection (b); (2) if the utilities exceeded the maximum
12level of investment under subsection (b-5) of this Section; (3)
13the required level of the utilities' contributions under
14subsection (b-10) of this Section; and (4) if these utilities
15have satisfied the performance metrics under subsection (f-2)
16of this Section.
17    During the infrastructure investment program's peak
18program year, a participating utility, other than a combination
19utility, serving fewer than 1,100,000 customers on January 1,
202013, shall create 1,000 full-time equivalent jobs in Illinois,
21such jobs measured by reference to the participating utility's
22average number of employees for the years 2008, 2009, and 2010
23as reported in the applicable Form 21 ILCC and the
24participating utility's average number of contractor positions
25for the years 2008, 2009, and 2010 and related to the provision
26of natural gas service; and a participating utility that is a

 

 

HB2414- 76 -LRB098 07848 JLS 37932 b

1combination utility shall create 250 full-time equivalent jobs
2in Illinois, such jobs measured by reference to the
3participating utility's average number of employees for the
4years 2009, 2010, and 2011 as reported in the applicable Form
521 ILCC and the participating utility's total number of
6contractor positions as of December 31 of the year immediately
7preceding the 10-year investment period and related to the
8provision of natural gas service. These full-time equivalent
9jobs shall include direct jobs, contractor positions, and
10induced jobs. A portion of the full-time equivalent jobs
11created by each participating utility shall include
12incremental personnel not accounted for in the baseline
13calculated under this paragraph that have been subsequently
14hired or retained. For purposes of this Section, "peak program
15year" means the consecutive 12-month period with the highest
16number of full-time equivalent jobs that occurs between the
17beginning of investment year 2 and the end of investment year
184.
19    A participating utility shall meet one of the following
20commitments, as applicable:
21        (1) Beginning no later than 180 days after a
22    participating utility that is a combination utility files a
23    performance-based formula rate tariff pursuant to
24    subsection (c) of this Section the participating utility
25    shall, except as otherwise provided in this subsection (b)
26    over a 10-year period, invest an estimated $330,000,000 in

 

 

HB2414- 77 -LRB098 07848 JLS 37932 b

1    gas transmission, distribution, and underground storage
2    system upgrades, modernization and compliance projects,
3    and training facilities, including, but not limited to:
4            (i) distribution plant, including mains, services,
5        meters, regulators, measuring and regulating station
6        equipment, and structures and improvements;
7            (ii) transmission plant, including mains,
8        measuring and regulating station equipment, and
9        structures and improvements;
10            (iii) underground storage plant, including
11        compression station equipment and structures,
12        measuring and regulating station structures and
13        equipment, reservoirs, wells, lines, and gas
14        purification equipment;
15            (iv) state of the art gas transmission and
16        distribution control facility;
17            (v) training facilities;
18            (vi) gas advanced metering infrastructure meters
19        including associated cyber secure data communication
20        network; and
21            (vii) small volume transport.
22        (2) Beginning no later than 180 days after a
23    participating utility serving fewer than 1,100,000
24    customers on January 1, 2013 that is not a combination
25    utility files a performance-based formula rate tariff
26    pursuant to subsection (c) of this Section the

 

 

HB2414- 78 -LRB098 07848 JLS 37932 b

1    participating utility shall, except as otherwise provided
2    in this subsection (b) over a 10-year period, invest an
3    estimated $1,200,000,000 in gas transmission,
4    distribution, and underground storage system upgrades, and
5    modernization and compliance projects, including, but not
6    limited to:
7            (i) distribution plant, including mains, services,
8        meters, regulators, measuring and regulating station
9        equipment, and structures and improvements;
10            (ii) transmission plant, including mains,
11        measuring and regulating station equipment, and
12        structures and improvements;
13            (iii) underground storage plant, including
14        compression station equipment and structures,
15        measuring and regulating station structures and
16        equipment, reservoirs, wells, lines, and gas
17        purification equipment; and
18            (iv) liquefied natural gas plant, including
19        structures and improvements, gas holders, liquefaction
20        equipment, and vaporizing equipment.
21    The investments in the infrastructure investment program
22described in this subsection (b) shall be incremental to the
23participating utility's annual capital investment program, as
24defined by, for purposes of this subsection (b), the
25participating utility's average capital spend for calendar
26years 2009, 2010, and 2011 as reported in Form 21 ILCC, except

 

 

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1in the case of a participating utility that is not a
2combination utility, serving fewer than 1,100,000 customers on
3January 1, 2013, for which the investments in the
4infrastructure program described in this subsection (b) shall
5be incremental to the participating utility's annual capital
6investment program, as defined by, for purposes of this
7subsection (b), the participating utility's average capital
8spend for calendar years 2008, 2009, and 2010 as reported in
9the applicable Form 21 ILCC; provided that where one or more
10utilities have merged, the average capital spend shall be
11determined using the aggregate of the merged utilities' capital
12spend reported in Form 21 ILCC for the years 2009, 2010, and
132011, as applicable. A participating utility may add a
14reasonable construction ramp-up and ramp-down time to the
15investment periods specified in this subsection (b). For each
16such investment period, the ramp-up and ramp-down time shall
17not exceed a total of 6 months.
18    Within 60 days after filing a tariff under subsection (c)
19of this Section, a participating utility shall submit to the
20Commission its plan, including scope, schedule, and staffing,
21for satisfying its infrastructure investment program
22commitments pursuant to this subsection (b). The submitted plan
23shall include a schedule and staffing plan for the next
24calendar year. The plan need not allocate the work equally over
25the respective periods, but should allocate material
26increments throughout such periods commensurate with the work

 

 

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1to be undertaken. No later than April 1 of each subsequent
2year, the participating utility shall submit to the Commission
3a report that includes any updates to the plan, a schedule for
4the next calendar year, the expenditures made for the prior
5calendar year and cumulatively, and the number of full time
6equivalent jobs created for the prior calendar year and
7cumulatively. If the participating utility is materially
8deficient in satisfying a schedule or staffing plan, then the
9report must also include a corrective action plan to address
10the deficiency. The fact that the plan, implementation of the
11plan, or a schedule changes shall not imply the imprudence or
12unreasonableness of the infrastructure investment program,
13plan, or schedule. Further, no later than 45 days following the
14last day of the first, second, and third quarters of each year
15of the plan, a participating utility shall submit to the
16Commission a verified quarterly report for the prior quarter
17that includes (i) the total number of full-time equivalent jobs
18created during the prior quarter, (ii) the total number of
19employees as of the last day of the prior quarter, (iii) the
20total number of full-time equivalent hours in each job
21classification or job title, (iv) the total number of
22incremental employees and contractors in support of the
23investments undertaken pursuant to this subsection (b) for the
24prior quarter, and (v) any other information that the
25Commission may require by rule.
26    With respect to the participating utility's peak job

 

 

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1commitment, if, after considering the participating utility's
2corrective action plan and compliance thereunder, the
3Commission enters an order finding, after notice and hearing,
4that a participating utility did not satisfy its peak program
5year job commitment described in this subsection (b) for
6reasons that are reasonably within its control, then the
7Commission shall also determine, after consideration of the
8evidence, including, but not limited to, evidence submitted by
9the Department of Commerce and Economic Opportunity and the
10participating utility, the deficiency in the number of full
11time equivalent jobs during the peak program year due to such
12failure. The Commission shall notify the Department of any
13proceeding that is initiated pursuant to this paragraph. For
14each full time equivalent job deficiency during the peak
15program year that the Commission finds as set forth in this
16paragraph, the participating utility shall, within 30 days
17after the entry of the Commission's order, pay $6,000 to a fund
18for training grants administered under Section 605-800 of the
19Department of Commerce and Economic Opportunity Law, which
20shall not be a recoverable expense.
21    With respect to the participating utility's investment
22amount commitments, if, after considering the participating
23utility's corrective action plan and compliance thereunder,
24the Commission enters an order finding, after notice and
25hearing, that a participating utility is not satisfying its
26investment amount commitments described in this subsection

 

 

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1(b), then the participating utility shall no longer be eligible
2to annually update the performance-based formula rate tariff
3pursuant to subsection (d) of this Section. In such event, the
4then current rates shall remain in effect until such time as
5new rates are set pursuant to Article IX of this Act, subject
6to retroactive adjustment, with interest, to reconcile rates
7charged with actual costs.
8    If the Commission finds that a participating utility is no
9longer eligible to update the performance-based formula rate
10tariff pursuant to subsection (d) of this Section, or the
11performance-based formula rate is otherwise terminated, then
12the participating utility's voluntary commitments and
13obligations under this subsection (b) shall immediately
14terminate, except for the participating utility's obligation
15to pay an amount already owed to the fund for training grants
16pursuant to a Commission order.
17    In meeting the obligations of this subsection (b), to the
18extent feasible and consistent with State and Federal law, the
19investments under the infrastructure investment program should
20provide employment opportunities for all segments of the
21population and workforce, including minority-owned and
22female-owned business enterprises, and shall not, consistent
23with State and Federal law, discriminate based on race or
24socioeconomic status.
25    (b-5) Nothing in this Section shall prohibit the Commission
26from investigating the prudence and reasonableness of the

 

 

HB2414- 83 -LRB098 07848 JLS 37932 b

1expenditures made under the infrastructure investment program
2during the annual review required by subsection (d) of this
3Section and shall, as part of such investigation, determine
4whether the participating utility's actual costs under the
5program are prudent and reasonable. The fact that a
6participating utility invests more than the minimum amounts
7specified in subsection (b) of this Section or its plan shall
8not imply imprudence or unreasonableness.
9    If the participating utility finds that it is implementing
10its plan for satisfying the infrastructure investment program
11commitments described in subsection (b) of this Section at a
12cost below the estimated amounts specified in subsection (b) of
13this Section, then the participating utility may file a
14petition with the Commission requesting that it be permitted to
15satisfy its commitments by spending less than the estimated
16amounts specified in subsection (b) of this Section. The
17Commission shall, after notice and hearing, enter its order
18approving, approving as modified, or denying each such petition
19within 150 days after the filing of the petition.
20    In no event, absent General Assembly approval, shall the
21capital investment costs incurred by a participating utility,
22other than a combination utility, serving fewer than 1,100,000
23customers on January 1, 2013, in satisfying its infrastructure
24investment program commitments described in subsection (b) of
25this Section exceed $2,500,000,000 or, for a participating
26utility that is a combination utility, $380,000,000. If the

 

 

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1participating utility's updated cost estimates for satisfying
2its infrastructure investment program commitments described in
3subsection (b) exceed the limitation imposed by this paragraph,
4then it shall submit a report to the Commission that identifies
5the increased costs and explains the reason or reasons for the
6increased costs no later than the year in which the
7participating utility estimates it will exceed the limitation.
8The Commission shall review the report and shall, within 90
9days after the participating utility files the report, report
10to the General Assembly its findings regarding the
11participating utility's report. If the General Assembly does
12not amend the limitation imposed by this paragraph, then the
13participating utility may modify its plan so as not to exceed
14the limitation imposed by this paragraph, and may propose
15corresponding changes to the metrics established pursuant to
16subsection (f-1) or (f-2), as applicable, of this Section, and
17the Commission may modify the metrics and incremental savings
18goals established pursuant to subsection (f-1) or (f-2), as
19applicable, of this Section accordingly.
20    (b-10) All participating utilities shall make
21contributions for an energy low-income and support program or
22programs in accordance with this subsection. Beginning no later
23than 180 days after a participating utility files a
24performance-based formula rate tariff pursuant to subsection
25(c) of this Section and without obtaining any approvals from
26the Commission or any other agency other than as set forth in

 

 

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1this Section, regardless of whether any such approval would
2otherwise be required, a participating utility shall pay
3$500,000 per year for 10 years to the energy low-income and
4support program or programs, which is intended to fund customer
5assistance programs with the primary purpose being avoidance of
6imminent disconnection. Such programs may include:
7        (1) a residential hardship program that may partner
8    with community-based organizations, including senior
9    citizen organizations, and provides grants to low-income
10    residential customers, including low-income senior
11    citizens, who demonstrate a hardship;
12        (2) a program that provides grants and other bill
13    payment concessions to disabled veterans who demonstrate a
14    hardship and members of the armed services or reserve
15    forces of the United States or members of the Illinois
16    National Guard who are on active duty pursuant to an
17    executive order of the President of the United States, an
18    act of the Congress of the United States, or an order of
19    the Governor and who demonstrate a hardship;
20        (3) a budget assistance program that provides tools and
21    education to low-income senior citizens to assist them with
22    obtaining information regarding energy usage and effective
23    means of managing energy costs;
24        (4) a non-residential special hardship program that
25    provides grants to non-residential customers such as small
26    businesses and non-profit organizations that demonstrate a

 

 

HB2414- 86 -LRB098 07848 JLS 37932 b

1    hardship, including those providing services to senior
2    citizen and low-income customers; and
3        (5) a performance-based assistance program that
4    provides grants to encourage residential customers to make
5    on-time payments by matching a portion of the customer's
6    payments or providing credits towards arrearages.
7    The payments made by a participating utility pursuant to
8this subsection (b-10) shall be a recoverable expense. A
9participating utility may elect to fund either new or existing
10customer assistance programs, including, but not limited to,
11those that are administered by the participating utility.
12    Programs that use funds that are provided by a
13participating utility to reduce utility bills may be
14implemented through tariffs that are filed with and reviewed by
15the Commission. If a utility elects to file tariffs with the
16Commission to implement all or a portion of the programs, those
17tariffs shall, regardless of the date actually filed, be deemed
18accepted and approved, and shall become effective on the
19effective date of this amendatory Act of the 98th General
20Assembly. The participating utility shall file annual reports
21documenting the disbursement of those funds under this Section
22with the Commission. The Commission has the authority to audit
23disbursement of the funds to ensure they were disbursed
24consistently with this Section.
25    If the Commission finds that a participating utility is no
26longer eligible to update the performance-based formula rate

 

 

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1tariff pursuant to subsection (d) of this Section, or the
2performance-based formula rate is otherwise terminated, then
3the participating utility's voluntary commitments and
4obligations under this subsection (b-10) shall immediately
5terminate.
6    (c) A participating utility may elect to recover its
7delivery services cost through a performance-based formula
8rate approved by the Commission, which shall specify the cost
9components that form the basis of the rate charged to customers
10with sufficient specificity to operate in a standardized manner
11and be updated annually with transparent information that
12reflects the participating utility's actual costs to be
13recovered during the applicable rate year, which is the period
14beginning with the first billing day of January and extending
15through the last billing day of the following December. In the
16event the participating utility recovers a portion of its costs
17through automatic adjustment clause tariffs on the effective
18date of this amendatory Act of the 98th General Assembly, the
19participating utility may elect to continue to recover these
20costs through such automatic adjustment clause tariffs, but
21then these costs shall not be recovered through the
22performance-based formula rate, or the participating utility
23may elect to file at any time to terminate any or all such
24automatic adjustment clause tariffs and the Commission shall
25approve such filing no later than 45 days after such filing.
26    For purposes of this Section, including subsection (g),

 

 

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1"delivery services" means those services provided by the gas
2utility that are necessary in order for the gas storage,
3transmission, and distribution systems to function so that
4retail customers located in the gas utility's service area can
5receive gas supply from the gas utility or, to the extent
6authorized by statute, Commission rule, or the gas utility's
7tariffs, from suppliers other than the gas utility, and shall
8include, without limitation, standard metering and billing
9services; provided, however, that solely for purposes of
10subsection (g), costs of delivery services shall not include
11charges assessed to retail customers under any tariff for
12recovery of costs of clean up or remediation of manufactured
13gas plant sites or any tariff for recovery of energy efficiency
14costs and excludes reconciliation adjustments determined under
15subsection (d) of this Section.
16    In the event the participating utility, prior to the
17effective date of this amendatory Act of the 98th General
18Assembly, filed gas delivery services tariffs with the
19Commission pursuant to Section 9-201 of this Act that are
20related to the recovery of its gas delivery services costs that
21are still pending on the effective date of this amendatory Act
22of the 98th General Assembly, the participating utility may, at
23the time it files its performance-based formula rate tariff
24with the Commission, also file a notice of withdrawal with the
25Commission to withdraw the gas delivery services tariffs
26previously filed pursuant to Section 9-201 of this Act. Upon

 

 

HB2414- 89 -LRB098 07848 JLS 37932 b

1receipt of such notice, the Commission shall dismiss with
2prejudice any docket that had been initiated to investigate the
3gas delivery services tariffs filed pursuant to Section 9-201
4of this Act, and such tariffs and the record related thereto
5shall not be the subject of any further hearing, investigation,
6or proceeding of any kind related to rates for gas delivery
7services except that the rate case expense incurred by the
8participating utility with respect to such tariffs through the
9date of dismissal of such docket shall be recoverable through
10the performance-based formula rate tariff, regardless of the
11year in which the rate case expense was incurred. The
12participating utility shall attest to the amount of the rate
13case expense by verification from an officer, and such amount
14shall not be disallowed.
15    The performance-based formula rate shall be implemented
16through a tariff filed with the Commission consistent with the
17provisions of this subsection (c) that shall be applicable to
18all customers, excluding customers taking service under
19contracts entered into pursuant to Section 9-102.1 of this Act.
20The Commission shall initiate and conduct an investigation of
21the tariff in a manner consistent with the provisions of this
22subsection (c) and the provisions of Article IX of this Act to
23the extent they do not conflict with this subsection (c).
24Except in the case where the Commission finds, after notice and
25hearing, that a participating utility is not satisfying its
26investment amount commitments under subsection (b) of this

 

 

HB2414- 90 -LRB098 07848 JLS 37932 b

1Section, the performance-based formula rate shall remain in
2effect at the discretion of the participating utility. The
3performance-based formula rate approved by the Commission
4shall do the following:
5        (1) Provide for the recovery of the participating
6    utility's actual costs of delivery services that are
7    prudently incurred and reasonable in amount consistent
8    with Commission practice and law. The sole fact that a cost
9    differs from that incurred in a prior calendar year or that
10    an investment is different from that made in a prior
11    calendar year shall not imply the imprudence or
12    unreasonableness of that cost or investment.
13        (2) Reflect the participating utility's actual
14    year-end capital structure for the applicable calendar
15    year, excluding goodwill, subject to a determination of
16    prudence and reasonableness consistent with Commission
17    practice and law, except that the common equity ratio in
18    the year-end capital structure for the applicable calendar
19    year shall not be subject to a determination of prudence
20    and reasonableness where said ratio is within 200 basis
21    points of the common equity ratio approved by the
22    Commission and reflected in the most recent Final Order
23    resolving a participating utility's request for a general
24    rate increase entered prior to the enactment of this
25    Section.
26        (3) Include a cost of equity, which shall be calculated

 

 

HB2414- 91 -LRB098 07848 JLS 37932 b

1    as the sum of the following:
2            (A) the average for the applicable calendar year of
3        the monthly average yields of 30-year U.S. Treasury
4        bonds published by the Board of Governors of the
5        Federal Reserve System in its weekly H.15 Statistical
6        Release or successor publication; and
7            (B) 580 basis points.
8        At such time as the Board of Governors of the Federal
9    Reserve System ceases to include the monthly average yields
10    of 30 year U.S. Treasury bonds in its weekly H.15
11    Statistical Release or successor publication, the monthly
12    average yields of the U.S. Treasury bonds then having the
13    longest duration published by the Board of Governors in its
14    weekly H.15 Statistical Release or successor publication
15    shall instead be used for purposes of this paragraph (3).
16        (4) Permit and set forth protocols, subject to a
17    determination of prudence and reasonableness consistent
18    with Commission practice and law, for the following:
19            (A) recovery of incentive compensation expense
20        that is based on the achievement of operational
21        metrics, including metrics related to budget controls,
22        safety, customer service, efficiency and productivity,
23        and environmental compliance, each of which may be
24        measured specifically for the participating utility or
25        for the corporation of which the participating utility
26        is a part. Incentive compensation expense that is based

 

 

HB2414- 92 -LRB098 07848 JLS 37932 b

1        on net income or an affiliate's earnings per share
2        shall not be recoverable under the performance-based
3        formula rate;
4            (B) recovery of pension and other post employment
5        benefits expense, provided that such costs are
6        supported by an actuarial study;
7            (C) recovery of severance costs, provided that if
8        the amount is over $3,700,000 for a participating
9        utility, then the full amount shall be amortized
10        consistent with subparagraph (F) of this paragraph (4)
11        of this subsection (c);
12            (D) investment return at a rate equal to the
13        utility's weighted average cost of long-term debt on
14        the pension assets, net of deferred tax benefits, and
15        on any associated regulatory asset. "Pension asset"
16        means the excess, if any, of cumulative contributions
17        by the utility to a pension trust over cumulative
18        recognized pension expense. The "pension asset" is
19        determined as the net of following items, where items
20        (i) and (ii) combined represent the funded status of
21        the participating utility's pension plans recognized
22        on the participating utility's balance sheet, and
23        where item (iii) represents the components of pension
24        expense not yet recorded in earnings, but recognized
25        separately on the participating utility's balance
26        sheet:

 

 

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1                (i) cumulative contributions made by the
2            participating utility in a pension trust in
3            compliance with its obligations under its defined
4            benefit pension plans and any associated
5            investment earnings, gains, and losses;
6                (ii) the participating utility's projected
7            pension obligations calculated in accordance with
8            U.S. Generally Accepted Accounting Principles;
9                (iii) the participating utility's
10            pension-related regulatory assets or regulatory
11            liabilities representing unrecognized components
12            of pension cost and accounted for in accordance
13            with U.S. Generally Accepted Accounting
14            Principles;
15            (E) recovery of the expenses related to the
16        Commission proceeding under this subsection (c) to
17        approve this performance-based formula rate and
18        initial rates or to subsequent proceedings related to
19        the formula, provided that the recovery shall be
20        amortized over a 3-year period; recovery of expenses
21        related to the annual Commission proceedings under
22        subsection (d) of this Section to review the inputs to
23        the performance-based formula rate shall be expensed
24        and recovered through the performance-based formula
25        rate;
26            (F) amortization over a 5-year period of the full

 

 

HB2414- 94 -LRB098 07848 JLS 37932 b

1        amount of each charge or credit that exceeds $3,700,000
2        for a participating utility in the applicable calendar
3        year and that relates to a workforce reduction
4        program's severance costs, changes in accounting
5        rules, changes in law, compliance with any
6        Commission-initiated audit, or a single system event
7        or other similar expense, provided that any
8        unamortized balance shall be reflected in rate base.
9        For purposes of this subparagraph (F), changes in law
10        include any enactment, repeal, or amendment in a law,
11        ordinance, rule, regulation, interpretation, permit,
12        license, consent, or order, including those relating
13        to taxes, accounting, or to environmental matters, or
14        in the interpretation or application thereof by any
15        governmental authority occurring after the effective
16        date of this amendatory Act of the 98th General
17        Assembly;
18            (G) recovery of existing regulatory assets over
19        the periods previously authorized by the Commission;
20            (H) historical weather normalized billing
21        determinants; and
22            (I) allocation methods for common costs.
23        (5) Provide that if the participating utility's earned
24    rate of return on common equity related to the provision of
25    delivery services for the prior rate year (calculated using
26    costs and capital structure approved by the Commission as

 

 

HB2414- 95 -LRB098 07848 JLS 37932 b

1    provided in paragraph (2) of this subsection (c),
2    consistent with this Section, in accordance with
3    Commission rules and orders, including, but not limited to,
4    adjustments for goodwill, and after any Commission-ordered
5    disallowances and taxes) is more than 50 basis points
6    higher than the rate of return on common equity calculated
7    pursuant to paragraph (3) of this subsection (c) (after
8    adjusting for any penalties to the rate of return on common
9    equity applied pursuant to the performance metrics
10    provision of subsection (f) of this Section), then the
11    participating utility shall apply a credit through the
12    performance-based formula rate that reflects an amount
13    equal to the value of that portion of the earned rate of
14    return on common equity that is more than 50 basis points
15    higher than the rate of return on common equity calculated
16    pursuant to paragraph (3) of this subsection (c) (after
17    adjusting for any penalties to the rate of return on common
18    equity applied pursuant to the performance metrics
19    provision of subsection (f) of this Section) for the prior
20    rate year, adjusted for taxes. If the participating
21    utility's earned rate of return on common equity related to
22    the provision of delivery services for the prior rate year
23    (calculated using costs and capital structure approved by
24    the Commission as provided in paragraph (2) of this
25    subsection (c), consistent with this Section, in
26    accordance with Commission rules and orders, including,

 

 

HB2414- 96 -LRB098 07848 JLS 37932 b

1    but not limited to, adjustments for goodwill, and after any
2    Commission-ordered disallowances and taxes) is more than
3    50 basis points less than the return on common equity
4    calculated pursuant to paragraph (3) of this subsection (c)
5    (after adjusting for any penalties to the rate of return on
6    common equity applied pursuant to the performance metrics
7    provision of subsection (f) of this Section), then the
8    participating utility shall apply a charge through the
9    performance-based formula rate that reflects an amount
10    equal to the value of that portion of the earned rate of
11    return on common equity that is more than 50 basis points
12    less than the rate of return on common equity calculated
13    pursuant to paragraph (3) of this subsection (c) (after
14    adjusting for any penalties to the rate of return on common
15    equity applied pursuant to the performance metrics
16    provision of subsection (f) of this Section) for the prior
17    rate year, adjusted for taxes.
18        (6) Provide for annual reconciliations, as described
19    in subsection (d) of this Section, with interest, of the
20    delivery services component of revenue as reported in the
21    applicable Form 21 ILCC, excluding any reconciliation
22    adjustments under subsection (d) of this Section and any
23    adjustments under paragraph (5) of subsection (c) of this
24    Section, for each calendar year, beginning with the
25    calendar year in which the participating utility files its
26    performance-based formula rate tariff pursuant to

 

 

HB2414- 97 -LRB098 07848 JLS 37932 b

1    subsection (c) of this Section, with what the revenue
2    requirement would have been had the actual cost information
3    for the applicable calendar year been available at the
4    filing date.
5    The participating utility shall file, together with its
6tariff, final data based on its most recently filed Form 21
7ILCC, plus projected plant additions and correspondingly
8updated depreciation reserve and expense for the calendar year
9in which the tariff and data are filed, that shall populate the
10performance-based formula rate and set the initial rates under
11the formula. For purposes of this Section, "Form 21 ILCC" means
12the Annual Report of Electric Utilities, Licensees and/or
13Natural Gas Utilities" or any successor to that report that
14natural gas utilities are required to file with the Commission
15under Section 5-109 of this Act. Nothing in this Section is
16intended to allow costs that are not otherwise recoverable to
17be recoverable by virtue of inclusion in Form 21 ILCC or to
18authorize the Commission to alter Form 21 ILCC in a manner that
19would result in a level of cost recovery inconsistent with the
20intent of this Section.
21    After the participating utility files its proposed
22performance-based formula rate structure and protocols and
23initial rates, the Commission shall initiate a docket to review
24the filing. The Commission shall enter an order approving, or
25approving as modified, the performance-based formula rate,
26including the initial rates, as just and reasonable within 270

 

 

HB2414- 98 -LRB098 07848 JLS 37932 b

1days after the date on which the tariff was filed, or, if the
2tariff is filed within 14 days after the effective date of this
3amendatory Act of the 98th General Assembly, then by May 31,
42014. Such review shall be based on the same evidentiary
5standards, including, but not limited to, those concerning the
6prudence and reasonableness of the costs incurred by the
7participating utility, the Commission applies in a hearing to
8review a filing for a general increase in rates under Article
9IX of this Act. The initial rates shall take effect within 30
10days after the Commission's order approving the
11performance-based formula rate tariff.
12    Until such time as the Commission approves a different rate
13design and cost allocation methodology pursuant to subsection
14(e) of this Section, rate design and cost allocation
15methodology across customer classes shall be consistent with
16the Commission's most recent order regarding the participating
17utility's request for a general increase in its delivery
18services rates.
19    Subsequent changes to the performance-based formula rate
20structure or protocols shall be made as set forth in Section
219-201 of this Act, but nothing in this subsection (c) is
22intended to limit the Commission's authority under Article IX
23and other provisions of this Act to initiate an investigation
24of a participating utility's performance-based formula rate
25tariff, provided that any such changes shall be consistent with
26paragraphs (1) through (6) of this subsection (c). Any change

 

 

HB2414- 99 -LRB098 07848 JLS 37932 b

1ordered by the Commission shall be made at the same time new
2rates take effect following the Commission's next order
3pursuant to subsection (d) of this Section, provided that the
4new rates take effect no less than 30 days after the date on
5which the Commission issues an order adopting the change.
6    A participating utility that files a tariff pursuant to
7this subsection (c) must submit a one time $200,000 filing fee
8at the time the Chief Clerk of the Commission accepts the
9filing, which shall be a recoverable expense.
10    In the event the performance-based formula rate is
11terminated, the then current rates shall remain in effect until
12such time as new rates are set pursuant to Article IX of this
13Act, subject to retroactive rate adjustment, with interest, to
14reconcile rates charged with actual costs. At such time that
15the performance-based formula rate is terminated, the
16participating utility's voluntary commitments and obligations
17under subsection (b) of this Section shall immediately
18terminate, except for the participating utility's obligation
19to pay an amount already owed to the fund for training grants
20pursuant to a Commission order issued under subsection (b) of
21this Section.
22    (d) The participating utility shall file, on or before May
231 of each year, with the Chief Clerk of the Commission, its
24updated cost inputs to the performance-based formula rate for
25the applicable rate year and the corresponding new charges.
26Each such filing shall conform to the following requirements

 

 

HB2414- 100 -LRB098 07848 JLS 37932 b

1and include the following information:
2        (1) The inputs to the performance-based formula rate
3    for the applicable rate year shall be based on final
4    historical data reflected in the participating utility's
5    most recently filed annual Form 21 ILCC, plus projected
6    plant additions and correspondingly updated depreciation
7    reserve and expense for the calendar year in which the
8    inputs are filed. The filing shall also include a
9    reconciliation of the delivery services component of
10    revenue as reported in the applicable Form 21 ILCC,
11    excluding any reconciliation adjustments under subsection
12    (d) of this Section and any adjustments under paragraph (5)
13    of subsection (c) of this Section, for each calendar year,
14    beginning with the calendar year in which the participating
15    utility files its performance-based formula rate tariff
16    pursuant to subsection (c) of this Section, for the prior
17    rate year with the actual revenue requirement for the prior
18    rate year (determined using a year-end rate base) that uses
19    amounts reflected in the applicable Form 21 ILCC that
20    reports the actual costs for the prior rate year. Any
21    over-collection or under-collection indicated by such
22    reconciliations shall be reflected as a credit against, or
23    recovered as an additional charge to, respectively, with
24    interest calculated at a rate equal to the utility's
25    weighted average cost of capital approved by the Commission
26    for the prior rate year, the charges for the applicable

 

 

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1    rate year. Provided, however, that the first such
2    reconciliation shall be for the calendar year in which the
3    participating utility files its performance-based formula
4    rate tariff pursuant to subsection (c) of this Section and
5    shall reconcile (i) the delivery services component of
6    revenue as reported in the applicable Form 21 ILCC for such
7    calendar year with (ii) the revenue requirement determined
8    using a year-end rate base for that calendar year
9    calculated pursuant to the performance-based formula rate
10    using (A) actual costs for that year as reflected in the
11    applicable Form 21 ILCC, and, (B) for the first such
12    reconciliation only, the cost of equity, which shall be
13    calculated as the sum of 590 basis points plus the average
14    for the applicable calendar year of the monthly average
15    yields of 30-year U.S. Treasury bonds published by the
16    Board of Governors of the Federal Reserve System in its
17    weekly H.15 Statistical Release or successor publication.
18    The first such reconciliation is not intended to provide
19    for the recovery of costs previously excluded from rates
20    based on a prior Commission order finding of imprudence or
21    unreasonableness. Each reconciliation shall be certified
22    by the participating utility in the same manner that Form
23    21 ILCC is certified. The filing shall also include the
24    charge or credit, if any, resulting from the calculation
25    required by paragraph (6) of subsection (c) of this
26    Section.

 

 

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1        Notwithstanding anything that may be to the contrary,
2    the intent of the reconciliations is to ultimately
3    reconcile the delivery services component of revenue as
4    reported in the applicable Form 21 ILCC for such calendar
5    year, excluding any reconciliation adjustments under
6    subsection (d) of this Section and any adjustments under
7    paragraph (5) of subsection (c) of this Section, for each
8    calendar year, beginning with the calendar year in which
9    the participating utility files its performance-based
10    formula rate tariff pursuant to subsection (c) of this
11    Section, with what the revenue requirement determined
12    using a year-end rate base for the applicable calendar year
13    would have been had actual cost information for the
14    applicable calendar year been available at the filing date.
15        (2) The new charges shall take effect beginning on the
16    first billing day of the following January billing period
17    and remain in effect through the last billing day of the
18    next December billing period regardless of whether the
19    Commission enters upon a hearing pursuant to this
20    subsection (d).
21        (3) The filing shall include relevant and necessary
22    data and documentation for the applicable rate year that is
23    consistent with the Commission's rules applicable to a
24    filing for a general increase in rates or any rules adopted
25    by the Commission to implement this Section. Normalization
26    adjustments shall not be required. Notwithstanding any

 

 

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1    other provision of this Section or Act or any rule or other
2    requirement adopted by the Commission, a participating
3    utility that is a combination utility with more than one
4    rate zone shall not be required to file a separate set of
5    such data and documentation for each rate zone and may
6    combine such data and documentation into a single set of
7    schedules.
8    Within 45 days after the participating utility files its
9annual update of cost inputs to the performance-based formula
10rate, the Commission shall have the authority, either upon
11complaint or its own initiative, but with reasonable notice, to
12enter upon a hearing concerning the prudence and reasonableness
13of the costs incurred by the participating utility to be
14recovered during the applicable rate year that are reflected in
15the inputs to the performance-based formula rate derived from
16the participating utility's Form 21 ILCC. During the course of
17the hearing, each objection shall be stated with particularity
18and evidence provided in support thereof, after which the
19participating utility shall have the opportunity to rebut the
20evidence. Discovery shall be allowed consistent with the
21Commission's Rules of Practice, which Rules shall be enforced
22by the Commission or the assigned hearing examiner. The
23Commission shall apply the same evidentiary standards,
24including, but not limited to, those concerning the prudence
25and reasonableness of the costs incurred by the participating
26utility, in the hearing as it would apply in a hearing to

 

 

HB2414- 104 -LRB098 07848 JLS 37932 b

1review a filing for a general increase in rates under Article
2IX of this Act. The Commission shall not, however, have the
3authority in a proceeding under this subsection (d) to consider
4or order any changes to the structure or protocols of the
5performance-based formula rate approved pursuant to subsection
6(c) of this Section. In a proceeding under this subsection (d),
7the Commission shall enter its order no later than the earlier
8of 240 days after the participating utility's filing of its
9annual update of cost inputs to the performance-based formula
10rate or December 31. The Commission's determinations of the
11prudence and reasonableness of the costs incurred for the
12applicable calendar year shall be final upon entry of the
13Commission's order and shall not be subject to reopening,
14reexamination, or collateral attack in any other Commission
15proceeding, case, docket, order, rule or regulation, provided,
16however, that nothing in this subsection (d) shall prohibit a
17party from petitioning the Commission to rehear or appeal to
18the courts the order pursuant to the provisions of this Act.
19    In the event the Commission does not, either upon complaint
20or its own initiative, enter upon a hearing within 45 days
21after the participating utility files the annual update of cost
22inputs to its performance-based formula rate, then the costs
23incurred for the applicable calendar year shall be deemed
24prudent and reasonable, and the filed charges shall not be
25subject to reopening, reexamination, or collateral attack in
26any other proceeding, case, docket, order, rule, or regulation.

 

 

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1    A participating utility's first filing of the updated cost
2inputs, and any Commission investigation of such inputs
3pursuant to this subsection (d) shall proceed notwithstanding
4the fact that the Commission's investigation under subsection
5(c) of this Section is still pending and notwithstanding any
6other law, order, rule, or Commission practice to the contrary.
7    (e) Nothing in subsection (c) or (d) of this Section shall
8prohibit the Commission from investigating, or a participating
9utility from filing, revenue-neutral tariff changes related to
10rate design and cost allocation methodology of a
11performance-based formula rate that has been placed into effect
12for the participating utility. Following approval of a
13participating utility's performance-based formula rate tariff
14pursuant to subsection (c) of this Section, the participating
15utility shall make a filing with the Commission within one year
16after the effective date of the performance-based formula rate
17tariff that proposes changes to the tariff to incorporate the
18findings of any final rate design orders of the Commission
19applicable to the participating utility and entered subsequent
20to the Commission's approval of the tariff. The Commission
21shall, after notice and hearing, enter its order approving, or
22approving with modification, the proposed changes to the
23performance-based formula rate tariff within 240 days after the
24participating utility's filing. Following such approval, the
25participating utility shall make a filing with the Commission
26during each subsequent 3-year period that either proposes

 

 

HB2414- 106 -LRB098 07848 JLS 37932 b

1revenue-neutral tariff changes or re-files the existing
2tariffs without change, which shall present the Commission with
3an opportunity to suspend the tariffs and consider
4revenue-neutral tariff changes related to rate design.
5    (f) Within 30 days after the filing of a tariff pursuant to
6subsection (c) of this Section, each participating utility
7shall develop and file with the Commission multi-year metrics
8designed as follows:
9    (f-1) For each participating utility that is a combination
10utility, the following metrics shall be designed to achieve,
11ratably (i.e., in equal segments, unless otherwise specified)
12over a 10-year period, improvement over baseline performance
13values as follows:
14        (1) System Integrity Improvement (under 49 CFR Part
15    192): Reduce the number of outstanding, non-hazardous
16    (Class 3) underground gas leaks on a participating
17    utility's gas system by 20% using a baseline of 2012.
18        (2) System Integrity Improvement (under 49 CFR 192):
19    Reduce the time period for leakage surveys on all
20    distribution pipelines that operate at 250 psig or greater
21    from every 5 years to once each calendar year, not to
22    exceed 15 months, that are in a Class 3 or Class 4
23    Location.
24        (3) Public Education and Emergency Responders: 100%
25    increase in the number of annual face to face informational
26    and training meetings to enhance education and provide

 

 

HB2414- 107 -LRB098 07848 JLS 37932 b

1    appropriate pipeline safety information to all
2    stakeholders, including emergency responders, public
3    officials, excavators, customers, safety advocates, and
4    members of the public living in the vicinity of pipelines,
5    using 2012 as a baseline.
6        (4) Third Party Excavation Damage: Reduce third party
7    excavation damage with a 10% reduction in the number of
8    damages per 1000 locate requests for natural gas
9    facilities, using a baseline of 2012.
10        (5) Integrity Management: Beginning in year 2 of the
11    participating utility's 10-year performance metric period,
12    install or replace 65 miles of gas transmission pipeline
13    facilities to upgrade and modernize the gas delivery
14    infrastructure and establish records and maximum allowable
15    operating pressures in accordance with Federal Department
16    of Transportation regulations. Install automatic or remote
17    controlled shut-off valves, or equivalent technology,
18    where economically, technically, and operationally
19    feasible on transmission pipelines constructed or entirely
20    replaced.
21        (6) Gas System Performance Monitoring: Increase the
22    number of new and upgraded gas transmission and
23    distribution system remote monitoring devices by 20% to
24    enhance and expand system pressure monitoring capabilities
25    and data acquisition, using a baseline of 2012.
26        (7) Reduction in Issuance of Estimated Gas Bills: 50%

 

 

HB2414- 108 -LRB098 07848 JLS 37932 b

1    improvement using a baseline of the average number of
2    estimated gas bills for the years 2009 through 2011.
3        (8) Opportunities for minority-owned and female-owned
4    business enterprises: Design a performance metric
5    regarding the creation of opportunities for minority-owned
6    and female-owned business enterprises consistent with
7    state and Federal law using a base performance value of the
8    percentage of the participating utility's capital
9    expenditures that were paid to minority-owned and
10    female-owned business enterprises in 2011.
11    (f-2) For each participating utility serving fewer than
121,100,000 customers on January 1, 2013, that is not a
13combination utility, to achieve, over a 10-year period,
14improvement over baseline performance values as follows:
15        (1) System Integrity Improvement (under 49 CFR Part
16    192): Reduce the number of outstanding, non-hazardous
17    (Class 3) underground gas leaks on a participating
18    utility's gas system by 10% using a baseline of 2012.
19        (2) System Integrity Improvement: Reduce the number of
20    bare steel, cast iron, ductile iron, copper and Cellulose
21    Acetate Butyrate (CAB) plastic service pipes on a
22    participating utility's gas system by 30% using a baseline
23    of 2012.
24        (3) Public Education and Emergency Responders: 100%
25    increase in the number of annual face to face informational
26    and training meetings to enhance education and provide

 

 

HB2414- 109 -LRB098 07848 JLS 37932 b

1    appropriate pipeline safety information to all
2    stakeholders, including emergency responders, public
3    officials, excavators, customers, safety advocates, and
4    members of the public living in the vicinity of pipelines,
5    using a baseline of 2012.
6        (4) Third Party Excavation Damage: Reduce third party
7    excavation damage, with a 5% reduction in the number of
8    damages per 1,000 locate requests for natural gas
9    facilities, using a baseline of 2012.
10        (5) Integrity Management: Install 900 miles of gas
11    pipeline facilities to upgrade and modernize the gas
12    delivery infrastructure and establish records and maximum
13    allowable operating pressures in accordance with the
14    United States Department of Transportation regulations.
15    Install automatic or remote controlled shut-off valves, or
16    equivalent technology, where economically, technically,
17    and operationally feasible, on transmission pipelines
18    constructed or entirely replaced.
19        (6) Gas System Performance Monitoring: Increase the
20    number of new and upgraded gas transmission and
21    distribution system remote monitoring devices by 20% to
22    enhance and expand system pressure monitoring capabilities
23    and data acquisition, using a baseline of 2012.
24        (7) Opportunities for minority-owned and female-owned
25    business enterprises: Design a performance metric
26    regarding the creation of opportunities for minority-owned

 

 

HB2414- 110 -LRB098 07848 JLS 37932 b

1    and female-owned business enterprises consistent with
2    state and Federal law using a base performance value of the
3    percentage of the participating utility's capital
4    expenditures that were paid to minority-owned and
5    female-owned business enterprises in 2011.
6    The metrics shall include incremental performance goals
7for each year of the 10-year period, which shall be designed to
8demonstrate that the participating utility is on track to
9achieve the performance goal in each category at the end of the
1010-year period. The participating utility shall elect when the
1110-year period shall commence for the metrics set forth in this
12subsection (f), provided that it begins no later than 14 months
13following the date on which the participating utility begins
14investing pursuant to subsection (b) of this Section.
15    (f-5) The financial penalties applicable to the metrics
16described in subparagraphs (1) through (7) of subsection (f-1)
17shall be applied through an adjustment to the participating
18utility's return on equity of no more than a total of 30 basis
19points in each of the first 3 years, of no more than a total of
2034 basis points in each of the 3 years thereafter, and no more
21than a total of 38 basis points in each of the 4 years
22thereafter, as follows:
23        (1) With respect to each of the incremental annual
24    performance goals established pursuant to subparagraph (1)
25    of subsection (f-1), for each year that a participating
26    utility does not achieve each such goal, the participating

 

 

HB2414- 111 -LRB098 07848 JLS 37932 b

1    utility's return of equity shall be reduced as follows:
2    during year one, by 10 basis points; during years 2 and 3,
3    by 5 basis points; during years 4 through 6, by 6 basis
4    points; and during years 7 through 10, by 7 basis points.
5        (2) With respect to each of the incremental annual
6    performance goals established pursuant to subparagraphs
7    (2) and (6) of subsection (f-1), for each year that a
8    participating utility does not achieve each such goal, the
9    participating utility's return on equity shall be reduced
10    as follows: during years one through 3, by 5 basis points;
11    during years 4 through 6, by 6 basis points; and during
12    years 7 through 10, by 7 basis points.
13        (3) With respect to each of the incremental annual
14    performance goals established pursuant to subparagraph (5)
15    of subsection (f-1), for each year that a participating
16    utility does not achieve each such goal, the participating
17    utility's return on equity shall be reduced as follows:
18    during years 2 and 3, by 5 basis points; during years 4
19    through 6, by 6 basis points; and during years 7 through
20    10, by 7 basis points.
21        (4) With respect to each of the incremental annual
22    performance goals established pursuant to subparagraphs
23    (3) and (4) of subsection (f-1), the performance under each
24    goal shall be calculated in terms of the percentage of the
25    goal achieved. The percentage goal achieved for each of the
26    goals shall be aggregated and an average percentage value

 

 

HB2414- 112 -LRB098 07848 JLS 37932 b

1    calculated, for each year of the 10-year period. If the
2    participating utility does not achieve an average
3    percentage value for a given year of at least 100%, the
4    participating utility's return on equity shall be reduced
5    by 5 basis points.
6        (5) With respect to each of the incremental annual
7    performance goals established pursuant to subparagraph (7)
8    of subsection (f-1), for each year that a participating
9    utility does not achieve each such goal, the participating
10    utility's return on equity shall be reduced by 5 basis
11    points.
12    (f-6) The financial penalties applicable to the metrics
13described in subparagraphs (1) through (6) of subsection (f-2)
14shall be applied through an adjustment to the participating
15utility's return on equity of no more than a total of 30 basis
16points in each of the first 3 years, of no more than a total of
1734 basis points in each of the 3 years thereafter, and no more
18than a total of 38 basis points in each of the 4 years
19thereafter, as follows:
20        (1) With respect to each of the incremental annual
21    performance goals established pursuant to subparagraphs
22    (1), (2), (5), and (6) of subsection (f-2), for each year
23    that a participating utility does not achieve each such
24    goal, the participating utility's return on equity shall be
25    reduced as follows: during years one through 3, by 5 basis
26    points; during years 4 through 6, by 6 basis points; and

 

 

HB2414- 113 -LRB098 07848 JLS 37932 b

1    during years 7 through 10, by 7 basis points.
2        (2) With respect to each of the incremental annual
3    performance goals established pursuant to subparagraphs
4    (3) and (4) of subsection (f-2), the performance under each
5    goal shall be calculated in terms of the percentage of the
6    goal achieved. The percentage goal achieved for each of the
7    goals shall be aggregated and an average percentage value
8    calculated, for each year of the 10-year period. If the
9    participating utility does not achieve an average
10    percentage value for a given year of at least 100%, the
11    participating utility's return on equity shall be reduced
12    by 10 basis points.
13    (f-8) The financial penalties shall be applied as described
14in subsection (f-5) or (f-6), as applicable, for the 12-month
15period in which the deficiency occurred through a separate
16tariff mechanism, which shall be filed by the participating
17utility together with its metrics. In the event the
18performance-based formula rate tariff established pursuant to
19subsection (c) of this Section terminates, the participating
20utility's obligations under subsection (f-1) or (f-2), as
21applicable, and subsection (f-5) or (f-6), as applicable, of
22this Section and this subsection (f-8) shall also terminate,
23provided, however, that the tariff mechanism established
24pursuant to subsection (f) of this Section and subsection (f-5)
25or (f-6), as applicable, and this subsection (f-8) shall remain
26in effect until any penalties due and owing at the time of such

 

 

HB2414- 114 -LRB098 07848 JLS 37932 b

1termination are applied.
2    The Commission shall, after notice and hearing, enter an
3order within 120 days after the metrics are filed approving, or
4approving with modification, a participating utility's tariff
5or mechanism to satisfy the metrics set forth in subsection
6(f-1) or (f-2), as applicable, of this Section and subsection
7(f-5) or (f-6), as applicable, of this Section. On June 1 of
8each subsequent year, each participating utility shall file a
9report with the Commission that includes, among other things, a
10description of how the participating utility performed under
11each metric and an identification of any extraordinary events
12that adversely impacted the participating utility's
13performance. Whenever a participating utility does not satisfy
14the metrics required pursuant to subsection (f-1) or (f-2), as
15applicable, of this Section, the Commission shall, after notice
16and hearing, enter an order approving financial penalties in
17accordance with subsection (f-5) or (f-6), as applicable, of
18this Section. The Commission-approved financial penalties
19shall be applied beginning with the next rate year. Nothing in
20this Section shall authorize the Commission to reduce or
21otherwise obviate the imposition of financial penalties for
22failing to achieve one or more of the metrics established
23pursuant to subparagraphs (1) through (3) of subsection (f-1)
24or (f-2), as applicable, of this Section.
25    (g) On or before June 30, 2016, each participating utility
26shall file a report with the Commission that calculates the

 

 

HB2414- 115 -LRB098 07848 JLS 37932 b

12-year average percentage change in the average residential
2retail customer's total bill over the 2-year period ended
3December 31, 2015, that is attributable to a change in delivery
4services charges, by comparing a base year and a comparison
5year pursuant to the methodology specified in this subsection
6(g). For a participating utility that is a combination utility
7with more than one rate zone, the weighted average aggregate
8change shall be provided. For a participating utility that has
9separate delivery service rates for space heat and non-space
10heat customers which are in effect in either or both the base
11year and the comparison year, the space heat rates, when
12applicable, shall be used for purposes of this calculation. The
13report shall be filed together with a statement from an
14independent auditor attesting to the accuracy of the report.
15The cost of the independent auditor shall be borne by the
16participating utility and shall not be a recoverable expense.
17    For purposes of all calculations performed under this
18subsection (g), the average residential retail customer's
19assumed annual consumption, for the base year and the
20comparison year shall be assumed to be as follows: for a
21participating utility that is a combination utility, 785
22therms; and for a participating utility that is not a
23combination utility and served fewer than 1,100,000 customers
24on January 1, 2013, 1,100 therms.
25    The report filed with the Commission shall:
26        (1) Calculate an average residential retail customer's

 

 

HB2414- 116 -LRB098 07848 JLS 37932 b

1    total bill for natural gas service, expressed on a dollars
2    per year basis, for a base year using: (i) the average
3    residential retail customer's assumed annual consumption,
4    (ii) a delivery service charge, using the delivery service
5    rates in effect at the end of the December, 2013 billing
6    cycle, and (iii) a cost of gas supply, based on the
7    participating utility's average purchased gas adjustments
8    for the period 2008-2010, where such total bill for natural
9    gas service includes add-on taxes and riders.
10        (2) Calculate a delivery service charge for the base
11    year, using the average residential customer's assumed
12    annual consumption and the delivery service rates in effect
13    at the end of the December, 2013 billing cycle, where such
14    delivery service charge for natural gas service shall not
15    include add-on taxes and riders.
16        (3) Calculate a delivery service charge for the
17    comparison year, using the average residential customer's
18    assumed annual consumption and the delivery service rates
19    in effect at the end of the December, 2015 billing cycle,
20    where such delivery service charge for natural gas service
21    shall not include add-on taxes and riders. For purposes of
22    the calculation of the delivery service charge for the
23    comparison year any reconciliation adjustments determined
24    under subsection (d) of this Section shall be excluded by
25    multiplying each component of the delivery services rates
26    by a fraction whose denominator is the revenue requirement

 

 

HB2414- 117 -LRB098 07848 JLS 37932 b

1    that was used to derive the delivery service rates in
2    effect at the end of the December, 2015 billing cycle and
3    the numerator is this same revenue requirement adjusted to
4    remove any reconciliation for previous years.
5        (4) Calculate the 2-year average change in the average
6    residential retail customer's total bill attributable to a
7    change in delivery service charges by subtracting the
8    average residential retail customer's delivery service
9    charge in the base year from the average residential retail
10    customer's delivery service charge in the comparison year,
11    and dividing the result by the average residential retail
12    customer's total bill in the base year, and then dividing
13    the resulting percentage by 2.
14    In the event that the average annual increase for a
15participating utility that is a combination utility exceeds
162.5% or for a participating utility that is not a combination
17utility exceeds 5%, as calculated pursuant to this subsection
18(g), then this Section of this Act, other than this subsection,
19shall be inoperative as it relates to the participating utility
20and its service area as of the date of the report due to be
21submitted pursuant to this subsection (g) and the participating
22utility shall no longer be eligible to annually update the
23performance-based formula rate tariff pursuant to subsection
24(d) of this Section. In such event, the then current rates
25shall remain in effect until such time as new rates are set
26pursuant to Article IX of this Act, subject to retroactive

 

 

HB2414- 118 -LRB098 07848 JLS 37932 b

1adjustment, with interest, to reconcile rates charged with
2actual costs, and the participating utility's voluntary
3commitments and obligations under subsection (b) of this
4Section shall immediately terminate, except for the
5participating utility's obligation to pay an amount already
6owed to the fund for training grants pursuant to a Commission
7order issued under subsection (b) of this Section.
8    In the event that the average annual increase is 2.5% or
9less or 5.0% or less, as applicable, as calculated pursuant to
10this subsection (g), then the performance-based formula rate
11shall remain in effect as set forth in this Section.
12    The fact that this Section becomes inoperative as set forth
13in this subsection (g) shall not be construed to mean that the
14Commission may reexamine or otherwise reopen prudence or
15reasonableness determinations already made.
16    (h) This Section, other than this subsection (h), and
17Section 19-150.6 of the Act, are inoperative after December 31,
182023, for every participating utility, after which time a
19participating utility shall no longer be eligible to annually
20update the performance-based formula rate tariff pursuant to
21subsection (d) of this Section. At such time, the then current
22rates shall remain in effect until such time as new rates are
23set pursuant to Article IX of this Act, subject to retroactive
24adjustment, with interest, to reconcile rates charged with
25actual costs.
26    By December 31, 2023, the Commission shall prepare and file

 

 

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1with the General Assembly a report on the infrastructure
2program and the performance-based formula rate. The report
3shall include the change in the average amount per therm paid
4by residential customers, as defined in subsection (g) of this
5Section, between June 1, 2014 and May 31, 2023. The report
6shall include separate sections for each participating
7utility. The fact that this Section becomes inoperative as set
8forth in this subsection shall not be construed to mean that
9the Commission may reexamine or otherwise reopen prudence or
10reasonableness determinations already made.
11    (i) Nothing in this Section is intended to legislatively
12overturn the opinion issued in People ex rel. Lisa Madigan v.
13Ill. Commerce Comm'n, Nos. 1-10-0936, 1-10-1790, 1-10-1846,
14and 1-10-1852 cons. (Ill. App. Ct. 1st Dist. Sept. 30, 2011).
15This amendatory Act of the 98th General Assembly shall not be
16construed as creating a contract between the General Assembly
17and the participating utility and shall not establish a
18property right in the participating utility.
19    (j) While a participating utility may use, develop, and
20maintain broadband systems and the delivery of broadband
21services, voice-over-internet-protocol services,
22telecommunications services, and cable and video programming
23services for use in providing delivery services and Gas AMI
24functionality or application to its retail customers,
25including, but not limited to, the installation,
26implementation and maintenance of Gas AMI system upgrades as

 

 

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1defined in Section 19-150.6 of this Act, a participating
2utility is prohibited from offering to its retail customers
3broadband services or the delivery of broadband services,
4voice-over-internet-protocol services, telecommunications
5services, or cable or video programming services, unless they
6are part of a service directly related to delivery services or
7Gas AMI functionality or applications as defined in Section
819-150.6 of this Act, and from recovering the costs of such
9offerings from retail customers.
 
10    (220 ILCS 5/19-150.6 new)
11    Sec. 19-150.6. Provisions relating to Gas Advanced
12Metering Infrastructure Deployment Plan.
13    (a) For purposes of this Section:
14    "Gas Advanced Metering Infrastructure" or "Gas AMI" means
15the communications hardware and software and associated system
16software that creates a network between advanced gas meters and
17utility business systems and allows the collection and
18distribution of gas-related information to customers and other
19parties in addition to providing information to the utility
20itself.
21    "Gas Advanced Metering Infrastructure Benefits" may
22include, but are not limited to, the following:
23        (1) Reduction in estimated gas bills.
24        (2) Reduction in monthly and off-cycle meter reading
25    costs.

 

 

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1        (3) Reduction in meter reprogramming costs due to
2    remote programmability.
3        (4) Reduction in unmetered and unbilled usage due to
4    earlier identification of meter problems and tampering.
5        (5) Reduction in vehicle emissions due to reduction in
6    manual meter reading.
7        (6) Improved and more timely information available to
8    customers to assist with energy management and cost
9    savings.
10        (7) Improved information for the development of new
11    energy efficiency programs.
12        (8) Improved information for more efficient gas system
13    operation.
14        (9) Improved safety of gas operations.
15    "Cost-beneficial" means a determination that the benefits
16of a participating utility's Gas AMI Deployment Plan exceed the
17costs of the Plan as initially filed with the Commission or as
18subsequently modified by the Commission. This standard is met
19if the present value of the total benefits of the Gas AMI
20Deployment Plan exceeds the present value of the total costs of
21the Gas AMI Deployment Plan. The total cost shall include all
22utility costs reasonably associated with the Gas AMI Deployment
23Plan. The total benefits shall include the sum of avoided
24costs, including avoided utility operational costs, avoided
25consumer commodity costs, and avoided societal costs
26associated with the production and consumption of natural gas,

 

 

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1as well as other societal benefits, including reductions in the
2emissions of harmful pollutants and associated avoided
3health-related costs, other benefits associated with natural
4gas energy efficiency measures.
5    "Participating utility" has the meaning set forth in
6Section 9-244.5 of this Act.
7    (b) Each participating utility that has an investment plan
8including Gas AMI under Section 9-244.5 of this Act shall file
9a Gas AMI Deployment Plan with the Commission within 180 days
10after the filing of a tariff pursuant to subsection (c) of
11Section 9-244.5. The Gas AMI Deployment Plan shall provide for
12investment over a 10-year period that is sufficient to
13implement the Gas AMI Deployment Plan across its entire
14delivery service territory in a manner that is consistent with
15subsection (b) of Section 9-244.5 of this Act. The Gas AMI
16Deployment Plan shall contain:
17        (1) the participating utility's Gas AMI vision
18    statement that is consistent with the goal of developing a
19    cost-beneficial Advanced Gas Metering Infrastructure;
20        (2) a statement of Gas AMI strategy that includes a
21    description of how the participating utility evaluates and
22    prioritizes technology choices to create customer value,
23    including a plan to enhance and enable customers' ability
24    to take advantage of Gas AMI functionality beginning at the
25    time an account has billed successfully on the Gas AMI
26    network;

 

 

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1        (3) a deployment schedule and plan that includes
2    deployment of Gas AMI to all customers for a participating
3    utility other than a combination utility, and to 56% of all
4    customers for a participating utility that is a combination
5    utility;
6        (4) annual milestones and metrics for the purposes of
7    measuring the success of the Gas AMI Deployment Plan in
8    enabling Gas AMI functionality; and enhancing consumer
9    benefits from gas system upgrades; and
10        (5) a plan for consumer education to be implemented by
11    the participating utility.
12    The Gas AMI Deployment Plan shall include open standards
13and internet protocol to the maximum extent possible consistent
14with cyber-security, and shall maximize, to the extent
15possible, a flexible gas meter platform that can accept remote
16device upgrades and contain sufficient internal memory
17capacity for additional storage capabilities, functions and
18services without the need for physical access to the meter.
19    The Gas AMI Deployment Plan shall secure the privacy of
20personal information and establish the right of consumers to
21consent to the disclosure of personal energy information to
22third parties through electronic, web-based, and other means in
23accordance with State and Federal law and regulations regarding
24consumer privacy and protection of consumer data.
25    After notice and hearing, the Commission shall, within 60
26days of the filing of a Gas AMI Deployment Plan, issue its

 

 

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1order approving, or approving with modification, the Gas AMI
2Deployment Plan if the Commission finds that the Gas AMI
3Deployment Plan contains the information required in
4paragraphs (1) through (5) of this subsection (b) and further
5finds that the implementation of the Gas AMI Deployment Plan is
6likely to be cost-beneficial. A participating utility's
7decision to invest pursuant to a Gas AMI Deployment Plan
8approved by the Commission shall not be subject to prudence
9reviews in subsequent Commission proceedings. Nothing in this
10subsection (b) is intended to limit the Commission's ability to
11review the reasonableness of the costs incurred under the Gas
12AMI Deployment Plan. A participating utility shall be allowed
13to recover the reasonable costs it incurs in implementing a
14Commission-approved Gas AMI Deployment Plan, including the
15costs of retired meters and radio modules, and may recover such
16costs through its tariffs, including the performance-based
17formula rate tariff approved pursuant to subsection (c) of
18Section 9-244.5 of this Act.
19    (c) The Gas AMI Deployment Plan shall secure the privacy of
20the customer's personal information. "Personal information"
21for this purpose consists of the customer's name, address,
22telephone number or other personally identifying information,
23as well as information about the customer's natural gas usage.
24Utilities, their contractors or agents, and any third party who
25comes into possession of such personal information shall not
26disclose such personal information to be used in mailing lists

 

 

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1or to be used for other commercial purposes not reasonably
2related to the conduct of the participating utility's business.
3Utilities shall comply with the consumer privacy requirements
4of the Personal Information Protection Act that are in effect
5as of the effective date of this amendatory Act of the 98th
6General Assembly and as amended thereafter.
7    (d) On April 1 of each year beginning the year following
8approval of the participating utility's Gas AMI Deployment
9Plan, each participating utility that has an investment plan
10including Gas AMI under Section 9-244.5 of this Act shall
11submit a report regarding the progress it has made toward
12completing implementation of its Gas AMI Deployment Plan. This
13report shall:
14        (1) describe the Gas AMI investments made during the
15    prior 12 months and the Gas AMI investments planned to be
16    made in the following 12 months;
17        (2) provide sufficient detail to determine the
18    participating utility's progress in meeting the metrics
19    and milestones identified by the participating utility in
20    its Gas AMI Deployment Plan; and
21        (3) identify any updates to the Gas AMI Deployment
22    Plan.
23    Within 21 days after the participating utility files its
24annual report, the Commission shall have authority, either upon
25complaint or its own initiative, but with reasonable notice, to
26enter upon an investigation regarding the participating

 

 

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1utility's progress in implementing the Gas AMI Deployment Plan
2as described in paragraph (1) of this subsection (d). If the
3Commission finds, after notice and hearing, that the
4participating utility's progress in implementing the Gas AMI
5Deployment Plan is materially deficient for the given Plan
6year, then the Commission shall issue an order requiring the
7participating utility to devise a corrective action plan,
8subject to Commission approval and oversight, to bring
9implementation back on schedule consistent with the Gas AMI
10Deployment Plan. The Commission's order must be entered within
1190 days after the participating utility files its annual
12report. If the Commission does not initiate an investigation
13within 21 days after the participating utility files its annual
14report, then the filing shall be deemed accepted by the
15Commission. The participating utility shall not be required to
16suspend implementation of its Gas AMI Deployment Plan during
17any Commission investigation.
18    The participating utility's annual report regarding Gas
19AMI Deployment Plan year 10 shall contain a statement verifying
20that the implementation of its Gas AMI Deployment Plan is
21complete, provided, however, that if the participating utility
22is subject to a corrective action plan that extends the
23implementation period beyond 10 years, the participating
24utility shall include the verification statement in its final
25annual report. Following the date of a Commission order
26approving the final annual report or the date on which the

 

 

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1final report is deemed accepted by the Commission, the
2participating utility's annual reporting obligations under
3this subsection (d) shall terminate, provided, however, that
4the participating utility shall have a continuing obligation to
5provide information, upon request, to the Commission regarding
6the Gas AMI Deployment Plan.
7    (h) If Section 9-244.5 of this Act becomes inoperative with
8respect to one or more participating utilities as set forth in
9subsection (g) of that Section, then Sections 9-244.5 and
1019-150.6 of this Act, other than this Section, shall become
11inoperative as to each affected participating utility and its
12service area on the same date as Section 9-244.5.
 
13    Section 99. Effective date. This Act takes effect upon
14becoming law.